McMoRan Exploration Co. Q1 2008 Earnings Call Transcript

| About: McMoRan Exploration (MMR)

McMoRan Exploration Co. (NYSE:MMR)

Q1 2008 Earnings Call

April 17, 2008 10:00 am ET


Kathleen L. Quirk - Senior Vice President of Finance and Business Development, and Treasurer

Richard C. Adkerson – Co-Chairman

James R. Moffett – Co-Chairman


Brian Kuzma – JP Morgan

Noel Parks - Ladenburg Thalmann

Michael Henzi - Sterne, Agee

Ronald Geffen - Burnham

Gregg Brody – JP Morgan


Welcome to the McMoRan Exploration first quarter 2008 conference call. (Operator Instructions) I would now like to turn the conference over to Kathleen Quirk, Senior Vice President and Treasurer.

Kathleen L. Quirk

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

Our conference call today is being broadcast live on the Internet and anyone may listen to the call by accessing our website homepage and clicking on the webcast link for the conference call. We also have several slides to supplement our comments this morning, and you can access the slides on our 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 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 presentation materials and press release, and to the risk factors described in our SEC filings.

On the call today are McMoRan’s Co-Chairmen, Jim Bob Moffett, and Richard Adkerson. I’ll briefly summarize the financial results and then turn the call over to Richard, who will be reviewing our recent performance and outlook. As usual, after our remarks, we’ll open up the call for questions.

Today, McMoRan reported net income applicable to common stock of $32 million or $0.46 per diluted share for the first quarter of 2008. This compared with a net loss applicable to common stock of $14.9 million or $0.53 per share for the first quarter of 2007.

Our net income from continuing operations for the first quarter of 2008 totaled $37.2 million, and it included a loss of $41.6 million or $0.49 per fully diluted share for mark-to-market charges on our open oil and gas derivative contracts.

You’ll recall we entered into derivative contracts in connection with our acquisition of Newfield shelf properties of last year and these derivative contracts have not been designated as hedges for accounting purposes and are subject to fair value adjustments each period.

Our first quarter results also included a realized cash loss of $3.6 million associated with the derivative contracts that were settled during the quarter.

Our diluted net income per share reflects full conversion of McMoRan’s outstanding 6% convertible senior notes, the 5.25% convertible senior notes, and our mandatory preferred stock, and the dilutive effect of outstanding stock options and warrants. And that added about 31.2 million shares in our diluted EPS calculation.

You’ll see from the press release the data provided that our first quarter results reflect strong performance from our producing properties and continued positive drilling results at the Flatrock field. Our first quarter production averaged 294 million equivalents per day net to McMoRan that compared with 70 million a day in the first quarter of last year.

Our average production was higher than our previously reported estimate on January 18 of 270 million a day for the quarter because of stronger performance from the properties that we acquired last August and from production from the Flatrock No. 1 well.

Our oil and gas revenues during the quarter totaled $292 million. This compared to $51 million during the first quarter of 2007. About 55% of our revenues in the first quarter of 2008 were from natural gas. Our realized gas prices in the first quarter were $9.06 per Mcf. That was 20% higher than the year-ago period’s average of $7.59 per Mcf and for oil and condensate increased 80% to an average of $97 per barrel compared with $54 per barrel in the year-ago period.

We generated strong cash flows during the quarter. Our earnings before interest, taxes, depreciation and exploration expenses totaled $228 million. Operating cash flows net of interest and working capital of $29 million for working capital totaled $173 million during the quarter.

We funded $51 million of capital expenditures during the quarter and reduced our debt by $144 million. That included $111 million in reduction of borrowings on our credit facility. And at the end of the quarter, we had $163 million borrowed.

We also completed privately negotiated transactions since the beginning of the year to convert a portion of our 6% convertible notes into equity. That reduced our debt by $32 million, which included $7 million in transactions that were settled in April. And we converted those notes into 2.2 million shares of common stock under the terms of the notes at $14.25 conversion price.

Basic shares outstanding at the end of the quarter totaled 55.6 million. Assuming conversion of all of the convertible securities we would have approximately 85.5 million shares outstanding.

Now I’d like to turn the call over to Richard, who will be referring to the slide materials that are included on our website.

Richard C. Adkerson

It’s a real pleasure to be able to talk about the results we had in our first quarter. All of us couldn’t be more pleased or excited about where we are with McMoRan today and the progress that we’ve made over the quarter and looking back into 2007.

I’ll go through the slides. Jim Bob will be here to talk about the details of our exploration program and our operations, and we can respond to questions. The financial data that Kathleen just reviewed with you is on Slide 3, the highlights. And just stepping back from it, there are some things that really jump out at you in looking at this.

We had 27 Bcf equivalents of production in the first quarter. Our production rate exceeded what our plan was of 294 million a day versus 270 and that reflects two factors. It reflects the performance of the properties we acquired from Newfield. That was a big objective that we had in managing the shallower production on the shelf that we bought from Newfield. And our team did a great job in keeping those production volumes up, and as well as the additions from our new discoveries.

Net incomes net of the mark-to-market number for our derivative contracts, we had to enter into those contracts to secure the financing that we had to buy the Newfield properties. So we have not entered into other derivative contracts since the initial hedge program we put into place.

Significant amount of cash earnings at this rate we’ll be approaching $1 billion on an annual basis, $173 million of cash flow, which is net of $29 million of working capital uses. Capital expenditures coming in as expected. And so we are achieving our objective of generating cash in addition to our investment in our business and significantly reducing the debt that we incurred in the acquisition.

That’s shown on the Slide 4. Mid-year last year at the time we made the acquisition, we had $1.2 billion of debt, which excludes our two issues of convertible notes, which are both now well in the money. That amount, the $1.2 million, has been reduced now in essentially three quarters to $466 million. So we are on track to de-lever the company as we anticipated doing when we made the acquisition.

The production growth has been significant, of course, with the addition of the new properties and our new discoveries. And the really good thing about the chart on Page 5 is we’ve been able to maintain the significant level of production we had during the fourth quarter going into the first quarter of this year. And looking forward, we anticipate strong production throughout 2008 with the opportunity to increase it from our exploration activity.

Another really good change for McMoRan is illustrated on the chart on Page 6. A year ago when we would look at our top field for production, it was a handful of good properties. Today, we’re much more diverse in the sense that we have a larger group of properties that are providing significant production to us.

That, of course, serves to mitigate the risk of oil and gas production since we have a number of properties and, to the extent, we were to inquire our production issues with the property, it’s not so significant now, and we have the opportunity to make it up with other significant producing properties.

Along with the Newfield transaction last year, it was really a positive event to have had the Flatrock discovery occurring in roughly the same time period that we made the acquisition. From our initial well at Flatrock, we felt that we were having a major discovery event for our company. And the subsequent drilling and production activities that we’ve had at this field validate what we thought from the very outset.

And this is exactly the type of property that we’ve been targeting with our strategy that we’ve been pursuing a number of years in looking for these deeper pools of significant reservoirs that are associated with shallower production.

Drilling, geological analysis, is confirming our belief that the sands at Flatrock were deposited over a large area of low relief, a very broad structure. Sand quality improved in the No. 2 well versus discovery well. The sands are having high production rates.

And of course, because this is located in this OCS 310 Mound Point area where there was significant shallower production, we’re able to use those production facilities that were developed for the shallower production to bring these significant wells on-stream and generating cash very quickly after the discovery.

The chart on Page 8 spots these wells that we’ve been drilling. They are in the federal offshore area of South Marsh Island Block 212, which is just north of Block 217 where we had had earlier discoveries in our Hurricane Deep prospects. On Block 212, over 200 wells had been drilled at a shallower horizons.

Following the drilling of our discovery well at Flatrock, we have completed drilling of the first extension well. We have two wells drilling, and we now have sites for two further wells as we delineate this field, develop it and continue exploration. And it will be a significant focal point of our operations as we go forward.

A cross-section of the Flatrock field is presented on Page 9. We’ve been talking now for six years about this significant area, 150,000-acre position that we’ve had that is testing Miocene age sands in the Rob-L, the Operc, and Gyrodina as it was drilled throughout this area. We’ve been able to see production in each of these sand sections.

The Hurricane/Hurricane Deep prospects at Block 217 saw production in the Rob-L and Gyrodina. We have now seen significant Operc production and Rob-L production at Flatrock. And you’ll see the extension of these sand packages as they go across the entire lease position area.

The four wells that have either been drilled or are drilling at Flatrock are summarized on the chart on Page 10. And you can see they’re characterized. And this is, of course, in very shallow water, but with multiple sand packages stacked on top of each other that have significant thickness. The No. 1 discovery well is currently producing 50 million a day gross, 12 million to our company for our net interest from a very prolific sand, which was not the thickest sand that we saw in that well, which will be produced subsequently.

And then we had the very positive test of the No. 2 well, which also had very thick sands and tested at over 100 million a day of gas and almost 2,000 barrels a day of condensate. And we will have this on production by mid-year. And we are currently involved in drilling two subsequent wells and have two further locations.

The production test on the Flatrock No. 2 well, which is a picture on Page 11, is really a significant event. It just demonstrates the fundamental theory that we had with our deeper pool concept. And the fact that you have sands of the quality and thickness that are able to produce at these kinds of rates, is simply the validation of what we’ve been about with our strategy in putting together a lease position going back to 1999.

The success of this in this area is shown by the prospects and properties that we’ve drilled in the Mound Point OCS 310 area, as shown on Page 12. You’ll recall that we drilled wells initially, the JB Mountain, Mound Point wells in partnership with El Paso.

Subsequently, we’ve negotiated restructuring of that deal where we have direct rights to acreage with our partners, and which has led to a series of wells that have seen very significant sands throughout. You can see Flatrock is located in the Northwest section, and we have further opportunities as we go forward.

Its 150,000 acres in this total area. And that is shown on Page 13, where in red we have shown the area of where there was the significant historical production at Texaco’s Tiger Shoal and Mound Point fields. These are historical fields of significance to the natural gas industry in Louisiana.

Cumulatively, those two fields produced over 6 trillion cubic feet from wells that were essentially above 14,000 feet. Little drilling had been done below 15,000 feet in this area when we acquired the rights to this transaction in our farm-out deal with Texaco before the Chevron merger. Subsequently, you can see in the lined areas, the sections in this area of where we have established production through our drilling operations.

But the real story here is that we’re just now testing the potential of this area, because with the historical analysis of the migration of the structures and the drilling that we’ve done to date, we see very large areas with continued potential. And that’s where the focus of our exploration, our deep gas program, is going to be oriented towards as we go forward.

We have a well location and a prospect we’re calling Mound Point East, which is on Page 14. It’s located in state waters in State Lease 340, again, in less than 10 feet of water. We have a 32% working interest, 23% net revenue interest, drilling a well to 18,000 feet. We’re currently drilling at 7,800 feet. And we started this just at the end of the quarter. Its located 10 miles east of the Flatrock field.

In our press release, we indicate that it’s targeting similar deep geological features that we saw in Flatrock. And that’s illustrated on the cross-section diagram shown on Page 15. Again, we’re talking about the three sand packages that you’ve heard us mention so often, above this regional fault, the big blue fault, where we’ve seen the Rob-L, Operc and Gyrodina as the original Mound Point well saw shallow production in the Operc.

Now we’re following that sand deposition in the big structures that are in the area to test it to the east at the Mound Point East prospect. And it’s an exciting exploration prospect for us.

You can see then as we move south with the JB Mountain structures, the test that we’ve done with the original JB Mountain well, which was our original significant discovery in the area, and wells that we’ve drilled there that have, again, seen well developed sands.

And you can see the interrelationship of the deep production that we’ve seen at the Hurricane Deep and drilling in the Mound Point area. All of this is something that gives us the excitement we have for our ongoing exploration program in this big lease position.

Our acreage position overall is presented on the chart on Page 17. You can see the spot of the Flatrock area, OCS 310, State Lease 340, the 150,000-acre position. We’re also going to be talking about our ultra-deep plays where the well that we are now drilling at South Timbalier Block 168 well is underway. We control 25,000 acres there.

But the chart demonstrates the properties that we had before the Newfield deal in yellow, the held-by-production acreage we acquired from Newfield. And then the ultra-deep acreage we have rights to 1.5 million gross acres, including the 450,000 acres in the ultra-deep plays that we have across the shelf of the Gulf, a very significant acreage position that gives us lots of opportunities.

Talking about the ultra-deep play, it is drilling that is consistent with what we’ve been doing with our deep gas exploration program, where we’ve been drilling from 15 to 25,000 feet. It’s drilling to depths below that. But it is into Miocene age sands that have been established to be productive with that age sands in the deepwater drilling that’s been done off the shelf.

Shallower production is shown this chart on the Plio/Pleistocene section. We’ve been drilling the upper Miocene above 25,000 feet and then if we go along below the salt feature to test the lower Miocene sections that have been established to be so prolific in the deepwater drilling and to older age rocks below that.

To illustrate the point that we made on our road show last year, and which really talks about what this play is, there’s a cross-section on Page 19, which shows the location of several of the very prolific deepwater development projects that have been done by the industry into the Miocene-age sections drilled in deepwater.

And this illustrate that these same plays are now available to us in drilling on the shelf. We feel confident that our experience in drilling high pressure wells at depth in the Miocene age rocks on the shelf will give us the technical confidence to drill to depths that haven’t been drilled on the shelf before, and to have the opportunity of testing these big structures in these potentially very significant reservoirs without having to spend the hundreds of millions of dollars that’s required to explore and develop in the deepwater.

So that in and of itself is what gives us the real incentive to drill and look for the economics that are available to test this prospect in the shallow waters of the Gulf.

We’re pleased to say that we are now drilling on South Timbalier Block 168. You can see that on chart on Page 20. This is the prospect formerly called Blackbeard, which is located in 70 feet of water. We and our partners reentered that well on March the 18. So we’re currently drilling below 30,145 feet. Drilling overnight has proceeded in a normal fashion. The previous operator and the previous investor group had drilled this well to below 30,000 feet and suspended operations in the third quarter of 2006.

We acquired the rights to the prospect in our Newfield transaction, and our company is operating it with our co-owners in the property. The deepening will target the Miocene objectives that I talked about on the earlier slide. Our proposed total depth is below 31,000 feet, and we own a 32.3% working interest in this prospect. Along with Flatrock, it is an exceptional exploration opportunity for us.

The chart on Page 21 shows another set of properties that gives us additional exploration opportunities. These are producing properties that we acquired from the Newfield transaction. And each one of the properties that we’ve spotted on this chart had cumulative production in excess of 100 Bcfs of equivalent. What Jim Bob and our exploration team are now doing is evaluating these blocks to apply the concepts that we’ve used in our deeper pool theory to identify additional exploration opportunities.

We’ve spent money on seismic to understand the producing areas. This will give us some exploitation opportunities in the shallower production, but also an understanding of the opportunities for exploration of significance in the deeper horizons and in blocks associated with our area. The significance of this, and you can see the spread across the shelf of the Gulf, is illustrated by the recent activities in the Gulf of Mexico sales.

Over the last two sales by MMS on the shelf of the Gulf, $400 million has been spent on successful bids involving 1.7 million acres across the Gulf. That involves 372 blocks. And if you just assume that, of those 372 blocks where people spent money to buy leases and invested in seismic and geologic analysis, that 200 of those are drilled, there will be in the range of $2 to $3 billion probably spent on drilling activity across that shelf in the area where we own these leases.

The seismic analysis, the drilling activity, the potential development opportunities there will serve to create significant value for us as a major leaseholder across this area, another great opportunity for our company.

Looking forward in 2008, production is estimated for the year to average 285 million a day. That’s higher than we were talking about in our fourth quarter earnings release call, where we were targeting 270 million a day. This is a result, as I mentioned at the outset, of our improved performance in the first quarter.

Our recent drilling success at Flatrock does not take into account other exploration opportunities or exploration activities that may give us a chance to produce at higher levels. And we’re obviously going to work very hard to produce as much as we can to take advantage of the very favorable markets that we have available to us.

From a business standpoint, we’re going to focus on OCS 310/340 area with our Flatrock follow-up wells, our drilling at Mound Point East, other prospects that we have in that area. And then, as I mentioned, we are drilling this very exciting high potential well at South Timbalier 168.

We currently see our capital expenditures in the range of $250 million. That is comprised of $90 million for exploration/exploitation, $160 million in development costs, but as always, our capital spending is going to be driven by the opportunities that come to us.

Success in exploration could lead to additional exploration costs. And all the work we’re doing in identifying exploration opportunities could give us the opportunity to invest profitably in our business. And we’ll have the cash flows to do that.

On Page 23, you can see illustrations, modeled cash flow numbers. Our cash earnings at forward prices would be for 2008 at $975 million for the year. And then after reducing that for our capital spending and other requirements that would generate approximately $500 million of excess cash flows. And that excess cash flows gives us opportunity to invest in our business, but also to meet our primary objective of de-levering and reducing our debt as we go forward.

McMoRan is focused on improving its balance sheet and maintaining a strong balance sheet, which will enable us to grow. We’re committing capital to high potential opportunities. While we’re doing this, we’re managing the risk of exploration through developing drilling arrangements with our partners so that we can take our capital and spread it across a number of these high potential opportunities. And as I mentioned and showed, we’re generating the cash that we anticipated to allow us to de-lever.

Details of our hedge position are presented on Page 25. I’ll mention it again this was put in place in connection with the negotiations with our banks that supported the initial acquisition. We haven’t added to the hedge position. We’ll evaluate that as we go forward. When you see these losses from these hedge positions, that’s offset by the fact that the majority of our production is unhedged and we’re getting the benefit from it. It was just a necessary element that we had in arranging the financing.

We’re continuing to work with our Main Pass Energy Hub. That’s our former sulfur mine at Main Pass Block 299. The LNG market has gone away from the United States for now, but it’s going to be an important part of the gas market’s future as we go forward.

And this asset has the potential to be significant for our company, as the U.S. needs more imported natural gas to meet its energy needs for the future. We’re continuing with our discussions with suppliers. The facility that we’ve mentioned many times has a number of characteristics that are positive for development for an LNG facility, including its proximity to market, its location offshore, and its location in conjunction with the salt dome where we produce sulfur, which could be used for storage capacity.

We’re not spending a lot of money on this, but we want to make you aware that we see it as a potential valuable asset for our company in the future. And we’re maintaining it to keep it alive.

So, key investment highlights are just summarized on the last slide. We now have a company with significant reserves, growing production. We’re in this business for the leverage of exploration and we have a whole portfolio of high impact exploration prospects, which our recent success is validating the whole reason we put this strategy together.

We have one of the largest lease positions on the shelf. We’re generating strong cash flows. Our exploration team with its long track record of success is adding to that legacy as we go forward.

Our production-operating group is doing a great job in keeping our production volumes moving and in keeping these Newfield properties in a cash flow generating posture to take advantage of the good prices that we’re receiving and de-levering. We believe we have a company with a set of assets that gives an attractive risk profile with the opportunity of having the reward of the significant leverage on exploration that our prospects are providing us.

With that quick summary, we are pleased to have you on the call. And Jim Bob is here, and we are available for your questions.

Question-and-Answer Session


(Operator Instructions) Your first question will be from Brian Kuzma – JP Morgan.

Brian Kuzma – JP Morgan

Could you just touch on what you think you’ll do with your free cash flow once all your short-term debt is paid off? It looks like it could be as early as year-end.

James R. Moffett

Brian, as Richard has emphasized and I’ve emphasized over the last few years, we continue to accumulate this huge lease position. And presuming that we will continue to validate the deeper pool and ultra-deep play on the shelf are going to lead to more successes. We’re going to use that money to drill and develop that concept.

We’ve spent six or seven years now building our database and calibrating the 3D seismic to show the geometry of this deep and ultra-deep play. And with the confirmation now that we have been able to drill and prove that the sand packages that we anticipate are actually there as thick, high flow rates. And they’ll have to come on production quickly. That winning formula will be enhanced by the fact that we’ve got the money now to continue to pursue that.

Brian Kuzma – JP Morgan

You’ll have to do some development work around State Lease 340, but then also stepping out and doing some exploration work.

James R. Moffett

And hopefully more development packages come out of that. It’d be great if we could see our exploration and development packages average an equal amount. For instance, this year we’re spending $160 on development and $90 on exploration.

If we could get that to where that was at a 50/50, it’d be able to give us tremendous opportunities to grow by exploration success and exploitation success. And with having the cash to do it, so we don’t have to continue to borrow money to do it or raise equity, would give us a strong profile.

Richard C. Adkerson

Brian, you really raise an interesting thing to think about over a longer period of time. With success, we will be able to create lots of values. We’re going to look for opportunities if they come to us, to maybe reduce some of our debt and ahead of its scheduled maturity times, if the markets allow us to do that on an attractive basis.

And then our organization has a long history of taking steps to enhance shareholder value. And that’s what we’ll be doing with this company as we go forward, investing, because we have such great set of prospects and potential for additional prospects, and then over time, doing things to create values in the shares of our company.

Brian Kuzma – JP Morgan

And then if you look out at the prospect formerly known as Blackbeard, is there any chance that you decide we want to take this down deeper and test the Paleogene?

James R. Moffett

The only limitation we would have to that is a rig can go to 35,000 feet. Right now the rig is not ready to go below 35,000, which would get us close to that. But depending on what we see, Brian, we had great success cleaning out the cement plugs and got down with it for just under $13 million. Put ourselves in a position to drill new holes, which we’ve done over the last several days.

We’ve cautiously started drilling a new formation just because of all of the concerns that were expressed about what might happen as we drill deeper. We drilled about 103 feet of new hole and the new hole is drilling routine. Obviously, at these depths, we continue to be cautious and note every change in drilling rate. But we’re drilling at 18 for mud, got no mud losses. I hate to say it’s routine, because we’re drilling at this depth, below 30,000 feet on the shelf, which is deeper than anybody has seen Miocene formation.

But using our deep drilling techniques that we’ve used to drill to 25,000 feet seems to be adequately keeping this well drilling, as I say, as deep wells go. So far, everything is routine. And so if we see that the drilling conditions continue, we’ve got the ability to set one additional 7-inch liner. We are drilling out from under a 9.5-inch liner. And you can set one more 7-inch liner if we want to go deeper than the 32,000 that is in the original TD of the original Blackbeard prospect, we can go to 35. That’s the capability of the rig.

And the structure is there all the way down and whatever whether it’s Miocene, Eocene, or pre-Eocene. Whatever these rocks are they’re giving us these strong seismic reflectors that attracted everybody to this big Blackbeard prospect initially. If things go routine, we are here to drill it.

Brian Kuzma – JP Morgan

So this project sounds like it is below budget for the first time.

James R. Moffett

Well, yes. We feel very fortunate that we were able to get down to 30,000 feet for just under $13 million. That was about our expectations. If we can make 150 feet a day, as you see, we can quickly find out whether this next 1,000/1,500 feet has got this pressure regression and the sand factors that we anticipate that we can push setting right above.

But we just drilled 103 feet of it. Obviously, we baby-sit this thing every minute of the day. And we’ll see if we can’t get this thing drilled down. We don’t have an LWD; it’s too deep and too hot. So we’ll drill down and we’ll run wireline logs to confirm what we drilled.

The only thing we have now is a mud log, which at this depth is virtually for safety. It monitors the temperature of the mud and the gas that comes out of the mud and when it comes to the surface. And we try to analyze samples but coming up from this depth, that’s pretty difficult to do. So, we won’t really know what we’ve drilled until we get it drilled and all the bit changes every 1,000 feet or so. We’ll drop in and get a wireline log if we can continue to drill and have things go routine.

Brian Kuzma – JP Morgan

So we could have results potentially in the next month?

James R. Moffett

Absolutely, if we don’t have any mechanical problems, you can calculate it yourself. 100 feet a day with some circulating time, we could make 1,000 feet in 10 days. And every 500 feet, every 200 feet, we add to the bottom of this hole based on the geophysical interpretation we have, will serve to try to tell us whether or not this sand package in the Miocene is below the TD of the well at 30,050 feet.

So buckle your seat belt, everything is routine. We’ll keep you informed and hopefully be able to continue this routine, in quotations, deep drilling and cautiously move ahead to see if we can’t prove up some reservoir rock, which is the big risk of the play. That’s similar to what we have in the deep water.

As Richard mentioned to you when he went over the slide, we can correlate via satellite and lead directly to the Tahiti and Knotty Head under harsh Miocene section. And it looks like it comes under this shelf, but we’re fixing to hopefully find out.

Brian Kuzma – JP Morgan

What do you think it would cost to drill a new development well out here, if this is successful?

James R. Moffett

Well, using 20/20 hindsight after looking at the well that was drilled to originally, we believe you can drill a much slimmer hole. Because of the unknowns that the people that drill the original well, they designed a well that set 20-inch at 12,500 feet, which proved to be a very expensive proposition.

We think you can slim that down significantly because based on the drilling of the first well, you never saw higher than 16.5 mud until you got to a depth of approximately 26,500 feet. And that’s routine for us. We think you can set a much smaller stream of casing at 20,000 feet, 13 and 3-inch possibly, and still end up with nine and five inch casing at about approximately the same depth.

As you do that, it’s based on our experience of drilling to 26,000 feet. The deepest we’ve drilled is 25 – 24.7, I believe it is. We think we can do that for just over $50 million. So, if we’re successful out here using a slimmer hole and not setting as many strings of pipe as was done in the original hole, again using 20/20 hindsight since we seen the result of the drilling of the first well, we think we can significantly lower the cost of development wells.


Your next question will be from Noel Parks - Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

On the slide you did point to a former Newfield property where you’re going to be making some investments, given the strong cash flows you’re going to have, the debt pay down happening faster than expected. Do you see that altering the risk profile of the types of properties you might be looking at over the next 12 months, just given that you have a little bit more flexibility there? Or do you think you’d be more likely to instead step up activities during, on the development level?

James R. Moffett

The answer to that question is both. We’ve been looking ever since we bought the properties, giving it thorough review both at the Plio/Pleistocene part of this section to see if there’s any development opportunities off the existing platforms.

And obviously, the deeper pool that Richard discussed we’re looking at them and examining to see if there’s any deeper pool. And we have probably 30 areas that we are pursuing on the deeper pool, trying to get the data completely understood and looking at the sands that we can pull in under these shallower platform.

But to answer your question, we will still take a similar approach. We use the cash that we have available to us for both development and exploration. But these exploration targets, we realize even with all of the 3D work and applying our technique and technology that we probably will bring in some other partners to spread ourselves across more plays, keeping a significant interest somewhere between 35% and 50% interest across the board.

By bringing in other partners on a promoted basis, we reduce even more risk of these deeper pool. And since we have this big acreage portfolio and people are rushing back to the shelf to find drilling opportunities, we not only have leases that are exploration targets, but we have existing platforms.

As Richard said, there’s 372 tracks bought. There’s a huge opportunity for us there because with the $2 to $3 billion that will be drilled on leases offset to our leases, it just gives us that much more data. New sands that may be proven to be productive and offset tracks that would give us more information to further fine-tune our exploration targets.

And one interesting fact, we have 150 platforms, if we have about a $200 million liability on ultimately if the platforms are depleted, to reclaim those. If we can find additional reserves underneath those platforms, we can extend the life of those platforms, which means that you basically get a free completion because all you have to do is lay new flowlines.

And/or alternately, if people make discoveries on this 372 tracks in our vicinity as opposed to building the platforms, they are going to want to come to existing platforms. And if we can either get some processing fees, which would be very lucrative for us and/or lay off the reclamation costs on some of these prospects.

Let’s just say a third of our platforms might be on a property that has production even off of our block, if someone came to us and we could lay off the reclamation costs that could save us $50 to $75 million in reclamation costs.

So to answer your question, that’s a long answer to your question, we are going to deploy these assets that we have acquired through our legacy properties to our own lease acquisitions, our own farm out agreements, and the Newfield properties. We are going to be sure that we look at every aspect of value and try to create value for the shareholders.

Noel Parks - Ladenburg Thalmann

I know you’ve got plenty on your plate, certainly for the near term. As far as the larger acquisition market properties that may have been coming your way can you just comment on what you’re seeing. What pricing people are assuming as they are looking to sell. And maybe what price step you’re using in your own considerations?

James R. Moffett

Well, we look at acquisitions and there are always things out there. When we bought Newfield, if you recall, a lot of people thought we were going down a wrong way on a one-way street, because everybody said they were exiting the Gulf. The industry did a great job of camouflaging the interest that they were going to have in the lease 7/2/07, which happened immediately after our acquisition.

And lo and behold, a record sale takes place last year, the biggest in 18 years. And then right behind that this year comes even a bigger sale. So the interesting thing is that the price of poker has gone up considerably in the Gulf of Mexico. And of course, as the price goes up for leaseholds, the price goes up for properties that are up for sale.

We think we got in the market at exactly the right time. But now that we have the successes that we’ve had developing and continuing to produce the Newfield properties, and have the discoveries that we’ve been discussing most significantly in Flatrock, we’re going to look very hard at knowing when to hold them and knowing when to fold them. So, the properties that come up for sale have a lot of buyers, sovereign funds, etc., sticking their nose in the Gulf of Mexico.

So to summarize, when we bought the Newfield properties, people were under the influence that everybody was leaving the shelf, going to the shale plays and conventional plays and going to the deepwater. That psychology has been completely reversed.

So we have to take a hard look at whether this is the right time to hold them, and a part of what we have and as opposed to spending high prices because of the competition in some of the acquisitions that may come along. We never rule it out, but in general, that’s our current philosophy.


Your next question will be from Michael Henzi - Sterne, Agee.

Michael Henzi - Sterne, Agee

I have been told by the company that the January and February production had totaled about 280 million cubic feet equivalent a day. And you reported 294 million cubic feet a day. And if you ex that out that implies that the March production was 321 million cubic feet equivalent a day. I was curious if you could give me what the production rates were for January and February?

Kathleen L. Quirk

In January we averaged just under 275 million a day, I believe it was 273. February, just under 300 and March 312.

Michael Henzi - Sterne, Agee

Since you had a March level of 312, how is it that the second quarter guidance is only 285?

Richard C. Adkerson

Well, Michael, these are a large number of properties. And what we do when we give our guidance is we come up with our best estimates. Every day some properties produce more, some produce less. We’re out there trying to maximize it. We’re going to try to beat our estimates as we go forward.

But when we give you this guidance, it’s what our best view is of the aggregate production for the quarter. And when you’re looking at variances of that difference, it’s just part of the normal course of operating a group of properties like this. With the properties in the shelf have high production rates and production issues every day. So this is our best estimate, we’re going to try to beat it.

Michael Henzi - Sterne, Agee

On the website and in the presentations you had given, there was a slide showing a map of the greater Flatrock area in January. And I look and I see that the slide presented at Howard Weil and this morning for the same slide has a large new potential area, and it’s been labeled Gladstone. It’s usually significant when a company puts a new area on an old map. Could you give us some more color on what you’re seeing at Gladstone?

James R. Moffett

What that’s all about Michael, is that as we said from the inception not only with the Flatrock wells but the wells that we’ve already drilled in this 150,000 acre area, we’ve been looking at the data and we’ve been trying to calibrate the production in the Flatrock area.

For instance, Mound Point and Tiger Shoal are twin features. They both produced over 2.5 Tcf of sands from 6,500 feet down to 12,000 feet. What we’ve said from the beginning is that we ought to have the same production under Mound Point as we’ve now found at Flatrock.

So using the data and reprocessing seismic to actually target in on where we know the known plays are, we’ve tried to find areas, we have no Rob-L production currently at Mound Point. We’ve drilled Operc production, we’ve drilled Gyro production, but as prolific as the Rob-L is, at Flatrock, we’ve yet to find a productive Rob-L sand.

Now, the sands are developed in the wells we’ve drilled, but they’re just not in the sweet spot of production. Taking the data that we’ve gotten at Flatrock, the Gladstone areas are areas that look to be the highest potential Rob-L production, just comparing the data in the Flatrock, now that we know Flatrock has multiple Rob-L plays. And so that’s basically what has generated that prospect.

And there’s a prospect called Tom Sauk, which is in a deeper Gyro, not a play that we want to drill up dipped to the Mound Point No. 5. We already have Gyrodina production at JB Mountain and in the Mound Point 5, where we have a productive Gyro play, but it is only one out of about 16 sands. And there’s another 2,000 feet of sand. It’s wet in that well. We want to get up dipo to it.

And there are some interesting seismic events that we’ve now calibrated that suggest this may be a sweet spot to pull some of this Gyro out of water and fill up those sands. The Operc has the same opportunity because we already have Operc production in the El Paso No. 1 well. It’s been producing for over five years.

To summarize that, what we really are saying is that we hope that with the data we have from the wells that we drilled, including the new Flatrock discovery wells, in this area that we get better at trying to use this 3D seismic to reprocessing and find the sweet spot on the Rob-L, Operc and Gyrodina at Mound Point. In other words, try to find the Flatrock of Mound Point that we found under Tiger Shoal field.

That’s our challenge. We know the structure is bigger. It’s actually at a higher elevation. And our geologic says that that gum stuff ought to be there. The donkey’s there, we’ve just got to go pin the tail on the donkey and find the Rob-L and get in the right spot.

The biggest challenge we have is the Operc and the Rob-L and the Gyrodina sands are so thick, that you can put a lot of production in a fairly small acreage size. For instance, if you have 400 to 500 foot sand, which we have at numerous Operc and Gyrodina sands that are over 400 to 500 feet thick, if you get those and get them in a high position and fill them up, 500 feet of sand and 500 acres is about 0.5 Tcf.

And that’s why we’ve tried to show those areas and paint there where we think that there’s some potential for that. The current Mound Point East well that we’re drilling on the east side, we stepped over there, because we have some major leasehold positions with the state that has to be protected before February of ‘09.

And we’re just trying to be sure we examine every inch and get better as a result of our success in this area at pinning down these major reservoirs. They are big, they are potentially thick. And as we have proven with the Flatrock well, these things can flow high flow rates, 50 to 100 million a day without any problem. Huge opportunity, a huge challenge and then we hope we’re up to it.

Michael Henzi - Sterne, Agee

Jim Bob, is what you’re basically saying is that Gladstone and Mound Point could end up being Flatrock size, Flatrock/Hurricane size?

James R. Moffett

That’s exactly right. The structure and the logic of that, Michael, is that Mound Point is actually a bigger feature and structurally higher than Tiger Shoal. That’s why we’ve drilled the darn thing first. We started over there because when we first started here in 2000, all we had was the 3D geophysics that showed the structure underneath these two big fields.

And clearly Mound Point, it covers about twice the area as Tiger Shoal does on the deep. And it’s over 1,000 feet higher. So they were twin fields shallow, they ought to be twin fields deep. And we’ve already seen Operc and Gyrodina pay on the edges of this field. We’ve just got to see if there is a sweet spot and see if there is, in fact, a Flatrock that produces in the Rob-L, Operc, Gyrodina, which would give us a twin structure deep, just like the twin structure shallows are.


Your next question will be from Ronald Geffen - Burnham.

Ronald Geffen - Burnham

On the Flatrock 2 and 3, roughly, they were started drilling at the same time. The Flatrock 3 for some reason, you haven’t been able to get down too far, is there any problems you’re encountering?

James R. Moffett

Well, some of the mechanical problems that have been encountered have just been a couple of them have just been unlucky breaks. We should have been down in the well by now. The well drilled down and some different pipelines were used. And so for a couple of months they had low circulation, it had to be cured.

And frankly, the last episode which cost us another six weeks, the drill stream twisted off at a pin, which sometimes they do, and left some fish in the hole. Once that fish was recovered and the loss returns occurred. But that’s all under control and the well may be sidetracked for the third time.

Chevron is operating that well. We’re not operating it. But I think their plans are to drill a second bypass. They’ve never gotten below 17,000 feet, but to that depth the Operc, as we reported is running high and is productive in the same sands. So far, it’s producing 50 million down depth. We’ve got the whole Operc section below us.

Hopefully, the mechanical problem will be overcome here in the next several weeks, and if we can get that done in the next two or three weeks, we’d be able to see the rest of the Operc.

And it’s a sweet spot on the Operc, and there’s some big dig sands that haven’t been seen in the 228 because to the North, as you remember the diagram, we cut out some of the deeper Operc sands with the big old blue fault we talked about. So we think there’s anywhere from 500 feet to 1,000 feet of additional sands that we didn’t see at 228, and it’s on top of the Operc structure.

So mechanical problems, nothing that can’t be overcome, just a streak of bad luck, but hopefully they’ll get it under control and get that well down so we can get on with drilling on the fifth and sixth well. We’re on the fourth well now. We’re operating that well. We’ve drilled the surface pipe and we’ll be drilling out to go see the Rob-L and Operc objectives there.

Ronald Geffen - Burnham

And who’s going to be the operator on the fifth and sixth wells?

James R. Moffett

That hasn’t been determined yet.


Your next question will be from Gregg Brody – JP Morgan.

Gregg Brody – JP Morgan

How much additional capital expenditure is associated with the sidetracking of the third Flatrock?

James R. Moffett

Somewhere probably, $5 to $7 million.

Gregg Brody – JP Morgan

So what is the additional development CapEx? Where is that going? Of the $25 million incremental, so if $5 to $7 is for this sidetracking, there’s another $20 or so? CapEx this year for this quarter was increased by about $25 million for development purposes. If it’s not all for sidetracking, where is the rest going?

Richard C. Adkerson

The sidetracking is not part of the development costs. That’s included. The development cost includes the costs of actually upgrading facilities to bring wells on production, completing the wells, tying into production. With the success we’re having in Flatrock, the Tiger Shoal fields are being expanded significantly, but the cost of sidetracking and drilling these wells are part of our exploration budget.

Gregg Brody – JP Morgan

And is that factored in currently?

Richard C. Adkerson

Yes, all of this is factored into our plans.

James R. Moffett

And by the way just to be sure that you know, we have 25% of the over expenditure on the No. 3 well. Chevron has 45%, Plains has 30%, and we have 25%. So, the numbers I’ve been giving you are [8h] numbers.

Gregg Brody – JP Morgan

On your reclamation expenditures for the your abandonment expenditures for this year, I was just noticing you have $60 million remaining for the year? Did you actually incur $20 this quarter? I noticed on your 10-K you had $80 million forecasted?

Kathleen L. Quirk

$80 million was our original budget for reclamation for this year. And we’ve had some timing changes. And currently our estimate is $60 million.

Richard C. Adkerson

As we go forward with these reclamation costs, we evaluate those on a property-by-property basis and decide which ones needs to be done during certain timeframes. Certain of the cost we will time to contract for times when contractors have equipment available and on attractive terms.

And so we’re managing this with a view of doing what we need to do at certain times and then managing our costs to when we can do it at the lowest cost. So this is going to be a moving target as we go forward.

James R. Moffett

And Richard, as we said earlier, we’re watching closely to the activity that’s going to be generated on these new leases that have been bought. And if there’s activity adjacent to any of these platforms, we will use that as a very defining moment to try to reserve as much of these platforms where possible.

Reuse, as we can, either with exploration that might be generated directly offsets us or ideas that could be germinated by us examining the data from the wells that will be drilled offset to us. There’s going to be a real poker game with these 150 platforms with this new activity in the Gulf.

Richard C. Adkerson


Gregg Brody – JP Morgan

Of the $60 you have so far, will that be spread over the year? Is there a time of the year that you actually pay that?

Richard C. Adkerson

Well, it depends on when it’s contracted for. Its going to be spent over the year, but it’s not something that you can schedule as being allocated to any particular points of time. It just depends on when we contract it for.

And Jim Bob makes a great point there, the reclamation obligations that we stepped into because we bought Newfield’s entire shelf property. It includes two things, one is platforms for fields that are depleted and those platforms often have uses, either for using them at the site or moving them to other sites.

And then we have certain properties that we stepped into costs where they were damaged by the 2005 storms. And that’s what we’re managing to do, as I said, at times when we have to do it and then in a way that reduces our costs. And we’ve made some progress with that. We believe we can do this at less cost than we originally thought.

James R. Moffett

The new leases bought in the lease sale; the new activity out there turns these platforms, some of them that were considered liabilities into potential assets. And we’ve got to be very, very diligent and make sure we take advantage of the new activity that’s going on out there.

Gregg Brody – JP Morgan

Obviously Flatrock is very successful. I’m just trying to get a sense of what proven reserves might look like at the end of the year and if there’s an F&D number that you can give us a range, that might be helpful. If not, just maybe talk a little bit about how bookings might take place around the existing wells, how many offsets, etc.

James R. Moffett

Well, obviously the big number there is how much reserve we can move from probable and possible at Flatrock in particular. We had about a 3P reserve that was done by independent engineers of 0.5 Tcf to the 8/8. We think that’s a conservative number on the 3P, but these wells drilling, the number three well we just discussed, we’ve got to see what the Operc sand things look like and see how much development there is in the Gyro, to the south.

So the answer is that Flatrock field, as we get into drilling these six wells before the end of the year, could be a significant add for us, because as you will remember, at the end of the year we only had preliminary information on Flatrock. So our production will be about 100 Bcf this year and you’ve heard the numbers that we’ve been estimating that could be there if some of these Flatrock wells drill out.

So we could replace a good bit of our production right there by year end if we can confirm the rest of the 3P reserves and expand even those conservative noted by our site engineers. And you just heard us talk about Mount Point/Flatrock look-a-like, that we’re going to be looking at, plus all the other opportunities that are going to be the deeper pool depending on how many of those we can get drilled by year-end. So, there are some significant opportunities for us to add reserves that would replace production.

And of course, the performance of some of these wells that we were just talking to about our production in the first quarter that averaged in March over 310 million a day. If we can produce those wells and cheap production history that would suggest the reserves that were originally assigned to these numerous reservoirs or behind pipe could have upsides.

We could add reserves just through production history on the number of wells that are currently drilling. Of course, the other side of that is some of the wells will under perform.

So we have three ways to add reserves by the end of the year, one, through further defining the Flatrock/Mound Point area; the other properties on the deeper pool, properties that we’ll be drilling; and the results of a continued production from the multitude of properties that we acquired, see if production performance could enhance the ultimate reserve life of these wells.

Richard C. Adkerson

And production performance at Flatrock is going to be an important factor of that as well. The number one well is producing very well. And the second well with the big production test, it will be important to see what production rates we have, how pressures hold.

And it’s really early in the game there. It’s at a time when our reserve estimates are going to be very dynamic. And we’re seeing lots of good news about what we’re doing right now with it. But it’s too early to give us any specific outlook for it.

Gregg Brody – JP Morgan

When was the 3P reserve, that you gave, last updated? The 3P reserve for Flatrock, when did you last update that 0.5 T? When was that?

James R. Moffett

Well, that was at year end. That was what it looked like based on the initial well that had been drilled that you could have. With these eight reservoirs we found some extensive area. The wells we drilled in the first quarter have added significantly to that ability to predict and take that 3P into 2P or 1P number. That process is still ongoing, trying to analyze this.

And, of course, these are numbers that are done by independent engineers and who by nature have to be conservative because of all the SEC rules that you know about. Our own 3P numbers are bigger than those numbers, but they’re depending on whether or not these, as I said, these deeper Operc sands and possibly Gyrodina sands have some additional thicknesses to them.

And we know they’re very thick sands and the structure is going to be as big at depth as it is shallow. So further defining the Rob-L targets and further defining Operc and Gyrodina could add some significance to our 3P number.

Thanks for everybody being on the call. If you have other questions, let us know and we’ll be happy to answer them for you.

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