McMoRan Exploration Co. Q1 2009 Earnings Call Transcript

Apr.20.09 | About: McMoRan Exploration (MMR)

McMoRan Exploration Co. (NYSE:MMR)

Q1 2009 Earnings Call

April 20, 2009 10:00 am ET


Kathleen L. Quirk – Senior Vice President, Treasurer

Richard C. Adkerson – Co-Chairman

James R. "Jim Bob" Moffett – Co-Chairman


Nicholas Pope - Dahlman Rose & Co.


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

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

Kathleen L. Quirk

Thank you. Good morning, everyone, and welcome to McMoRan Explorations first quarter 2009 conference call.

Our results were released earlier this morning and a copy of the press release is available on our website at

Our conference call today is being broadcast live on the Internet. Anyone may listen to the conference call by accessing our website home page and clicking on the webcast link for the conference call.

We also have several slides to supplement our comment this morning and we'll be referring to the slides during the call. They're also available by accessing the webcast link on

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

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

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

McMoRan reported a net loss applicable to common stock of $63.2 million - $0.90 per share - for the first quarter of 2009 compared with net income applicable to common stock of $32 million - $0.46 per fully diluted share - for the first quarter of 2008.

Our first quarter results from continuing operations totaled a loss of $59.5 million that included net charges of $47.3 million, which included $39 million or $0.55 per share in impairment charges for certain fields to reduce their carrying value to fair value, $15.2 million or $0.23 a share in charges to exploration expense primarily relating to the Tom Sauk and Gladstone East exploration wells, which were determined to be non-commercial in the first quarter, $10.8 million of additional charges associated with hurricane damage to certain properties, and all this was net of an $18.7 million gain associated with the initial payment of insurance proceeds related to the September 2008 hurricanes. We're continuing to pursue an insurance claim and expect to recover additional proceeds in the future.

Our first quarter production averaged 198 million cubic feet of natural gas equivalents per day net to McMoRan that was lower than the year ago quarter but higher than the fourth quarter production of 162 million cubic feet of natural gas equivalents as we continue to restore production affected by the shut ins associated with Hurricane Ike.

Our first quarter oil and gas revenues totaled $95 million. That compared to $292 million during the first quarter of 2008. Our realized prices for gas in the first quarter were $4.88 per Mcf. That was 46% lower than the year ago average of $9.00 per Mcf. Our oil prices - $40.91 per barrel in the first quarter of 2009 - were lower substantially than last year's average of $97.40 per barrel.

Our realizations do not take into account the gains and losses on our derivatives contracts. During the first quarter we financially settled 3.4 Bcf of natural gas and 151,000 barrels of oil that were hedged through swap positions at an average price of $9 per Mcf and $71.93 per barrel, respectively. We received $18.1 million in cash for these positions which was reflected as a gain in our first quarter 2009 financial results.

Our first quarter earnings before interest, taxes, depreciation, and exploration expense totaled $68 million and our operating cash flow for the first quarter totaled $33.8 million.

Capital expenditures totaled $29.2 million in the first quarter.

And we ended the quarter with $95 million in cash and no amounts borrowed under our bank credit facility. We completed our borrowing base redetermination, semi-annual borrowing base redetermination in April, and the new borrowing base has been established at $235 million. Again, there's nothing drawn under the facility but we do use it for a letter of credit, a $100 million line of credit to support abandonment obligations. Our debt at the end of the first quarter totaled $375 million. That included $75 million in convertible senior notes.

Our shares outstanding currently approximate 70.5 million and assuming conversion of the remaining mandatory convertible preferred stock and convertible notes, McMoRan would have approximately 87.8 million shares outstanding.

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

Richard C. Adkerson

Good morning, everyone.

I'm going to be speaking from the slides and starting with Slide 3, we have a summary of the highlights that reflect our accomplishments during the first quarter when we had production of right at 200 million a day equivalents.

Flatrock Field continues to perform well - gross production rate of approximately 235 million a day; that's $44 million net of our company - and we expect first production from two new discoveries there, the 5 and 6 wells by midyear this year.

With our deep gas exploration program we have three wells in progress that we'll be talking about on this call - Ammazzo on South Marsh Island Block 251, Cordage, which is drilling at West Cameron Block 207, and then our Blueberry Hill prospect, where we're sidetracking our existing well there at State Lease 340 in the same area that our Flatrock field is producing the 150,000 acre position that we have at Tiger Shoal Mountain Point area just offshore of Louisiana.

We'll be continuing with that program with the drilling of the Sherwood Deep Prospect at High Island 133 later this year and then we'll be evaluating the information both that we gain from drilling our Blackbeard ultra-deep well, but also new information that we've obtained on sand deposition starting onshore and continuing into deep water. Jim Bob will be talking about that in a few minutes.

Financially, we had $95 million in cash at the end of the quarter with no amounts drawn on our bank credit facility. The financial summary that Kathleen just reviewed with you is presented on Page 4 and the details of our reported results and our income statement as well as the special items that went into this quarter's net income are detailed there for your information.

The productive wells that we have are spotted with our lease position on Page 5. You can see the significant production that we have at South Marsh Island 212, the Flatrock field, and then the number of fields where our production is spread over the shelf of the Gulf of Mexico and onshore in South Louisiana.

The quarter's production and our production continues to be affected by the curtailments resulting from the hurricanes of last September. Work continues to be done on the downstream facilities to bring this back on production but we still are limited, with 45 million a day approximately curtailed from what we'd otherwise be producing. We're currently at the 200 million a day level.

Our production during the second quarter is going to be slightly less than that as we will continue to be affected by the curtailments, but it also reflects some shut in activities at Flatrock to do maintenance work as well as to do some facilities work to allow us to produce wells in the future from there. The timing of when we get back to full production following the repairs on the downstream pipelines and facilities is still something that we just have to work through and get it on, but we will expect that to be on stream by later in the year.

We are pursuing substantial insurance recovery funds for the cost that we have incurred in dealing with hurricane damage. These costs are going to be funded over a multiyear period. To date we've received $20 million in initial payments for these costs that we've incurred.

The details of the producing wells and the wells we're bringing on production at Flatrock are included on Page 7. We currently have four wells that are producing, as I mentioned earlier. The field will be shut in during the second quarter for planned maintenance and expansion work that we need to get done and by midyear it'll be back on stream, along with production from the Number 5 and 6 wells.

The map of the Flatrock Field is included on Page 8. At year end Ryder Scott has assigned over 350 million Bcf equivalent of proved reserves to this field. That's 66 million net to McMoRan's interest. You can see it extends over Block 212 and the block to the south, the South Marsh Island, in 217. This is shallow water, 10 feet. And as I said we've drilled six successful wells to date and there will be continued opportunities to drill in this and other areas and that's shown on Page 9, where we have the OCS 310 area along with State Lease 340. This is the lease position that I mentioned earlier that extends from state waters into the federal waters.

The proven areas that we've established reserves on are shown in the lined areas that are outlined. The historical shallow production is in the dark red, where over 6 trillion cubic feet were produced above 14,000 feet by Texaco, now Chevron, historically in the Tiger Shoal and Mountain Point fields. And even though we've done drilling today, we have significant additional potential as shown in the lighter color red there that's outlined and this will continue to be an important area. You can see the Blueberry Hill in the southeast corner of this section and the significant potential that we're now testing with our sidetrack well there.

Our leases are shown on Page 10 that include our acreage that we've accumulated ourselves historically and then through the transaction with Newfield almost two years ago now. The ultra-deep acreage that we acquired is shown in the blue area and you can see the South Timbalier Block 168, where we had re-entered and drilled the Blackbeard well, and the interrelationship between the sand deposition from this area going onshore and into the deep water is an important opportunity for us that we will continue to be focused on.

The current prospect that we're drilling, the Ammazzo deep gas exploration prospect, lies south of the Mountain Point/Tiger Shoals area, our Flatrock area, but it's targeting one of the largest undrilled structures on the shelf of the Gulf of Mexico below 15,000 feet. It's positioned on the southern portion of the structural ridge that goes from Flatrock to JB Mountain. Because of the size of the structure it has very large potential. We began drilling this well in late November last year. We're currently at about 21,600 feet with a targeted depth to start at 24,500, shallow water 25 feet. But a big structure and Jim Bob's going to talk more about how this fits into our overall exploration analysis and approach right now.

We're also drilling a farm out prospect where we have a 50% interest in the well. This well was - drilling commenced on March 18th. We're already down to over 12,000 feet. It's at West Cameron Block 207, a targeted depth of 19,500 feet, significant [unrisked] potential and, again, something that fits our area.

The Blueberry Hill deep gas prospect is a feature off the Mountain Point field to the southeast section of our lease position in the area. We began re-drilling this well or sidetracking it at the end of March. We have a 32.3% net revenue interest. We're going to 24,000 feet. We re-entered the existing well bore. We're targeting the gyro sands that we encountered in the original exploratory well while we saw [inaudible] sands at the top of the structure. When we completed the sands for production, we ran into production issues that kept us from producing that. Our view is that the sands are likely to be better developed in a down dip position on the flank of the structure and because of the size of the structure we have very significant potential there on the order of 500 Bcf equivalents.

Now when we began our strategy back in the late 1990s and in recent years of drilling for these deep gas prospects in the shallow waters of the Gulf of Mexico and onshore, we were targeting significant potential prospects in excess of 100 Bcf equivalents and some were much larger than that. The well depths of our program were focused on between 15,000 and 25,000 feet associated with previous production at shallower depths, looking for these deeper-seated reservoirs in sands that were known to be productive along the Gulf Coast area.

Drilling these wells of course involves significant risk. Drilling is expensive. But discoveries tend to be large, with high flow rates, and they're located near existing infrastructure which allows us to develop the prospects on a relative basis with relatively less cost and also to do it very quickly.

With the Newfield acquisition we then got opportunities to drill on the shelf of the Gulf of Mexico prospects in the sand ages that have known to be productive in a significant way in the deep water. This goes out into the shelf of the Gulf into approximately 100 feet of water - it could be much shallower - very large reserve potentials; well depths below 25,000 feet up to 35,000 feet that are, as I mentioned, deep structures that are analogous to the deep water discoveries.

But again, because they're on the shelf, unlike the deep water prospects, they are near existing infrastructure with much shorter times to develop production and bring them on stream than those who invest in the deep water face with the development cost and timing that was required there.

Both these plays are new provinces, in effect, for the oil and gas exploration interest in the Gulf of Mexico and really give us very exciting opportunities to follow the sand deposition on shore and into the offshore areas and give this very significant prospects.

I'd like to ask Jim Bob to come in and talk about our recent new information and the way that we're analyzing it in terms of developing our strategy going forward.

Jim Bob?

James R. "Jim Bob" Moffett

Thank you, Richard.

Slide 15, if you'll note, is the slide which we had originally talked about when we started the ultra-deep play. I want to focus on the fact that what we were doing initially before the deepening of the Blackbeard well. We could see a [inaudible] time from the offshore deep-water play and were convinced that we could tie the Miocene and lower aged rocks right across the shelf.

And, as you'll see from the next slide, remember we deepened the Blackbeard well and when we deepened it we saw the Miocene section was some hydrocarbon variant sand. We've been re-studying all the data from that well and, of course, they're looking into the potential deepening of that well to the Wilcox. I'll explain why that's important and then attempt a new Wilcox completion or a Miocene completion.

In the meantime, offshore, if you'll notice the next slide, Slide 17, we want to point out to you that the significance of this Blackbeard well grows almost daily as we compare it to information that continues to come from the deep water wells. If you'll notice, we've got a circle there that's shown to be 90 miles by 136 miles. I want you to focus on the fact that at the bottom of that circle the dark red circle with the arrow pointing to it is the shelf edge.

And what's happened here is the deep water play stops at the shelf edge, which is a current shelf, but the shelf at the top of the Miocene deposition is what's important to the deposition of Miocene sands in the offshore shelf and deep water. If you go up and see the shelf and slope, it's shown just about through our Flatrock field. It's clear now as we get more velocity information and more seismic data, which we're tying in, we've now tied all the way back to the onshore, in particular to our Flatrock property, and what we see there is a basin that covers the entire shelf in our anchor position. There's no reason to separate the deep water from the shelf acreage because, as I say - I want to emphasize it one more time - the shelf is a current shelf, not the shelf that was in place at the time of the Miocene.

Also, the source area for all the sands are in the deep water as well as the sands that have been drilled in the onshore and now are going to be drilled on the shelf. You'll notice that's headed right toward the Flatrock/Blackbeard and of course has been responsible for the major sand deposition that's given these discoveries all the way from Thunder Horse to Tahiti.

It's important to note that all those features that are east-west just south of the shelf are primary structures in the Miocene and the Wilcox. There's not any primary structure out there that's been drilled that hasn't had hydrocarbons. That's significant because as we go back to the north and look at the shelf, all the Miocene and deeper structures that we see are primary structures, including Blackbeard, and we feel that each one of these, like the ones in the deep water, have an excellent opportunity to have major hydrocarbons.

If you'll turn to the next page, this is really a new evolving story which has had a major impact on our thoughts about how to develop the Blackbeard project and to pursue all of our other acreage. This is known as the so-called Yegua/Wilcox. And if you get a chance just kind of compare and look back from Slide 17 to 18. The Wilcox Basin, once again, the shelf edge today that exists has nothing to do with the limits of the Wilcox. It you'll look north you'll see way north of the current shoreline you have a shelf slope and that's where the shelf was at the time of the Wilcox.

The Wilcox, as we now are starting to understand - now meaning the industry, including Freeport McMoRan - the new wells that are being drilled have been drilled while we were drilling Blackbeard West and since we have moved off and are looking at the opportunity to complete that well or deepen it. The Shenandoah discovery down to the south of us, they tacked on to the jack in Cascade, which you've been reading about, but the important thing is as people have moved north of the most southerly Wilcox wells that are shown to the south there at Cascade jack, the sands are improving significantly in terms of sand quality.

Now you'll notice that there's a big - well, we call them the Holly Springs Delta, which is the same funnel of sands that were coming off the Mississippi River, and those sands are what's giving this Wilcox sort of a brand new prominence. The Wilcox Basin, as you can see, is two and a half times as big as the Miocene, and there's nobody in this deep water, deep gas or our shelf after the play began had any concept that the Wilcox was going to be this big a reservoir. We even hear word that over to the west on a prospect called El Dorado that the operator has encountered Yegua and possibly Wilcox production way to the west, which would be over 100 miles west of us.

And if you look at the next slide down, which is 19, there's the other big news that's starting to pop out as we tie the seismic and the drilling information from Blackbeard East. If you look to the north, once again there's a shelf slope in the Cretaceous which in Louisiana is the Tuscaloosa - in Texas it is the Woodbine - and that same sand funnel is headed right toward, as you can see, the acreage that we've been talking about. We believe that we've now been able to tie from Blackbeard offshore, the deep water, and back to the onshore right into the Flatrock area.

And if you'll notice, just north of Flatrock is the so-called traditional Tuscaloosa play, which was the big play that was drilled north of Baton Rouge in the so-called Port Hudson trend that was a huge drilling play in the 70s and 80s. We now believe that we've got a good correlation that gives us not only Wilcox potential on the shelf, but as you can see, in the 68 to 318-mile area it gives us the potential to have the Tuscaloosa.

So if you'll imagine the Miocene, Wilcox, Tuscaloosa in very shallow water, including right along the existing coastline, this is the largest new information on these structures that we're mapping, all the way back to the coastline, and we have several that are sitting just about under the Flatrock acreage that we have. Those areas are going to be seeing the Miocene, Wilcox, Tuscaloosa above 30,000 feet.

Now all of that information ties in and gives us more and more direction as to how to pursue the entire shelf, including our Blackbeard well, so it's the biggest play unveiled with the tying of the Blackbeard well to deep water and onshore. We have dozens of structures that we control. Once again, they're all primary structures, like the structures I pointed out in the Miocene. Since all of them are productive and the Blackbeard well to the depth we've drilled indicates hydrocarbons, we feel like this shelf area is the biggest new story in the Gulf of Mexico in 25 years. So these are huge structures that have potential of 1 to 10 to 15 Bcf - Tcf of gas, excuse me  with three separate petroliferous geologic ages that are well known in the Gulf of Mexico.

So, as you can see, the story continues to unfold and we're in the middle of this, drilling the shelf. We're the only one that's on the shelf drilling these deep wells. It's separated strictly by the current day shelf edge, which divides water depth from 600 feet to the coastline on the shelf. It's sort of our happy hunting ground.

So this is going to be an exciting time. As Richard said, we're managing our way through these price declines and keeping our cash flow so we can pursue this. We know how to do this. So stay tuned. This is going to be an exciting extension to the deep-water play that we've discussed and really the old onshore production.

I'll let Richard finish his operations report and then we'll take questions on all of the above.

Richard C. Adkerson

Thanks, Jim Bob.

We of course are having to respond to the lower natural gas prices and the impact that that has on our revenues and we're making progress in doing that. On Slide 20 we've detailed $75 million in projected savings that we're putting a plan in place to achieve versus the plan that we started the year with in January and that we talked about with our fourth quarter earnings release.

We're going to continue to manage our expenditures and be responsive to market conditions, but the new plan that we have in place involved reducing our capital expenditures, our exploration and development costs, from $230 million to $200 million. We've gone through a company wide effort to reduce cost levels at all areas in operating and administrative and we've identified $10 million of savings in that effort.

And then we had previously been aggressive in pursuing our reclamation activities beyond what was required by regulatory standards, and we've made a review of those projects and deferred certain of those discretionary projects as part of this effort to maintain liquidity. We've reduced our budget for reclamation for this year to $80 million and that represents a $35 million savings.

Our outlook for 2009, we expect to average production of approximately 250 million cubic feet of equivalents per day. We've reviewed our exploration program. We will continue with our deep gas shallow water program at Ammazzo, Blueberry Hill Sidetrack, the Cordage/Sherwood farm-outs and, as Jim Bob talked about, we'll continue to look for opportunities and expect to develop strategies for pursuing those through drilling following up on our ultra-deep wells and continuing that into the shelf.

Our capital expenditures, as I mentioned, are now estimated to be approximately $200 million. That's $100 million in exploration, $45 million in development. It includes $55 million of costs that were actually incurred in 2008 but will be cash funded in 2009.

As always, we'll continue to be reviewing opportunities and that will ultimately drive our spending. But including partner participation and so forth, we'll manage those prudently given our cash flow and balance sheet situation.

As I mentioned at the start, we're pursuing insurance proceeds. That'll depend on when we actually incur the costs to reclaim and remediate damage by the hurricanes, but that will be something that'll be coming in over the future months.

The company's cash flow situation is illustrated on Page 22. Using forward pricing, our EBITDAX projected amounts would be $280 million for 2009. You can see how that would vary depending on varying oil and gas prices.

Then our debt maturities, we are fortunate that we did delever following the Newfield acquisition and we don't have near-term debt maturity obligations and no amounts currently drawn on our bank credit facility. The initial maturity is a convertible note of $75 million due in 2011 and then $300 million of bond debt in 2014. We recently had our borrowing base redetermination, our semi-annual redetermination of our borrowing base, and that reflected the lower natural gas prices and oil prices from six months ago and it was set at $235 million.

We're going to manage our business to continue to have a strong balance sheet. Our capital spending is going to be driven by the opportunities that Jim Bob outlined for you, but we want to manage those within our existing cash and cash flows that we generate. We're going to commit capital to high potential opportunities, which is the strategy of this company, while we maintain this capital discipline and spread our risk through partner arrangements. Our company does have significant reserves, a good production profile, but the real key to us is our high-impact exploration opportunities and our large acreage position.

So we're on track, responding to the low gas price environment, and continuing our strategy of exposing our company and our shareholders to these great opportunities from our exploration program.

With that, Operator, we'll open the line for questions.

Question-and-Answer Session


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

Nicholas Pope - Dahlman Rose & Co.

A quick question on first quarter production. I see Flatrock Number 3 had 9 million a day gross production. Can you explain why that number was so low?

James R. "Jim Bob" Moffett

That's the Operc well that is in one of the lower Operc [inaudible]. It's shown some depletion. It'll be recompleted to one of the other lower Operc sands. That's the well that has about five of those Operc sands stacked on top of each other. We started at the bottom and not all available Operc sands are as widespread as some of the Operc 1 and 2 or the Rob-L. So it's produced at a high rate and then it's just been coming down. It'll be recompleted to one of the Operc sands right above it and production will jump back up as you come up the hole and recomplete those Operc sands.

Richard C. Adkerson

And, Nick, that's expected to happen during the second half of this year. These are stacked pays and we're not producing from multiple zones, we're not dually completing them, so this will happen over the life of this field, particular zones will deplete. We want to capture those reserves and once they're completed, as Jim Bob said, we'll recomplete and other zones of production will come back.

James R. "Jim Bob" Moffett

I might add that's [rigorous] recompletion, Nick, where you just go in with a wire line and set it with a cement plug and perforate the upper zone, so it's set up in a rigorous recompletion. We see that happening while we go through this shut in period to bring in two new wells and upgrade the production because when we shut in for the upgrade we'll be at 235 million a day; when we go back on production we'll be at 335 million a day. And that's why they're having to make these different remedial actions to get us up that extra 100 million a day. So it's a step back for a couple of weeks to get ready to go to the next level.

And of course we've got the Gyrodyne development to the south of the 233 well we just drilled which we hope is going to outline a significant Gyrodyne potential in those big Gyrodyne sands to take us to the next level of production.

Nicholas Pope - Dahlman Rose & Co.

With the new CapEx budget did any CapEx move from CapEx to the exploration expense, like Gladstone or Tom Sauk, did they move categories in any of that change?

Richard C. Adkerson

No. No, not really. We just, you know, exploration, we include exploration in our CapEx budget. Of course, dry holes are expensed under our accounting policy, but this reflects the actual plans we have for drilling exploratory wells, conducting exploration, and then the development activities that we know about right now.

James R. "Jim Bob" Moffett

Nick, if you remember, the Tom Sauk and Gladstone wells were step outs. The Tom Sauk well was 9 miles to the east back over to Mountain Point, where we continue, along with El Paso and Chevron, to try to prime the flat rock underneath that big structure.

And unfortunately, as we moved - I think the Gladstone well was 6 miles to the east; we tried to take the signature and move into Mountain Point - we got big thick sands in those two wells and unfortunately they're not hydrocarbon bearing.

That structure is so big, if you remember we called it Acropolis. The big sands in the Tom Sauk well, especially in the Gyrodyne, where we had one sand that was almost 1,000 feet thick, it's just north of Blueberry Hill. That's why we moved directly to Blueberry Hill, because we saw the big sands literally 2 miles to the north of Blueberry that ought to be around the flank of that dome. That's why we've waited to sidetrack it.

So you'll see in the next several quarters into next year that we really are going to focus on where and how do you pull these big thick sands in Mountain Point, if there is a flat rock underneath it. We know to the north we've had the El Paso well producing since 2001 from the Operc and there's Gyrodyne sand in the Mountain Point 5 well, so the sands have good distribution and we should be able to pin the tale on the donkey. But the first two step outs to try to take and put the pieces together on Mountain Point unfortunately were not successful.

Nicholas Pope - Dahlman Rose & Co.

And then just real quick, that EBITDAX estimate that you all have, does that include insurance recoveries in that estimate?

Kathleen L. Quirk

No, it does not.


And there are no further questions at this time.

Richard C. Adkerson

All right. Well, thanks, everyone, for participating. If you have follow up questions, as always, we're available. Have a good day.


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

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