Callon Petroleum Co (CPE) 2006 Q2 法說會逐字稿

[technical difficulty--first few minutes not broadcast] --second quarter, our production averaged 58 million cubic feet of gas a day, with natural gas representing about 49% of that total.

Current production rates from major properties are as follows. The Medusa field is producing 25,700 barrels of oil at 24.5 million cubic feet of gas a day. The A-6 well was scheduled to be recompleted this fall, however, due to better than anticipated relative oil performance, the recomplete has been delayed into 2007.

In addition, we had anticipated the A-5 well would deplete from the current zone, and be recompleted in the fourth quarter. However, the well is still producing 2,300 barrels a day, and 1.8 million cubic feet of gas a day, so the recompletion has also been rescheduled into 2007. We of course own a 15% working interest at Medusa.

At Habanero, current production is 8,500 barrels of oil at 11.5 million cubic feet of gas. This rate continues to decline due to the strong water drive in the #2 well, which is now approximately 47%. Because of the strong water drive, we anticipate enough up-depth sidetrack, or a new well will be drilled when we deplete the #2 well, sometime in late next year. We own 11.25% interest at Habanero.

In our Mobile Bay area fields, the current production is 8 million cubic feet of gas a day. We own an 83% interest out here. And at High Island 119, we're producing 10 million a day, about 160 barrels of oil from our three wells, and we own a 22.2% interest.

Production rate at the East Cameron Block 9 #1 well is approximately 5 million a day. We own a 61.7% interest there. And at North Padre Island 913 #1, we're producing at 15.3 million cubic feet of gas a day, and we own a 50% working interest.

At West Cam, at West Cameron Block 295, our #2 well is producing at a rate of 12.8 million cubic feet of gas and 75 barrels of oil. We had planned to perform an acid stimulation on the well to increase production, however, based on additional analysis, we decided not to ask that of the well and run the risk of sand production.

The #3 well is expected to commence production this month, at a rate of approximately 10 million a day. Initial production was expected in May, but was delayed by about approximately 90 days due to lack of availability of equipment and services. We're also drilling an offset to the #2 well, the #4 well. This well has reached total depth and is currently being evaluated. And we own a 20.5% working interest in the West Cameron 295 block.

At High Island 73, our #1 well is producing approximately 10 million cubic feet of gas a day. Again, we planned to open it, show, and produce it up for 20 million a day, but we decided not to pull it too hard and continue to produce it--10 million a day. We own a 33.7% working interest.

In addition to these wells, we have five other discoveries that should be online between now and the end of the third quarter, early fourth quarter. Initial production from these discoveries is currently scheduled to be later than we had announced in the last quarter. These delays are the result of industry competition, or installation equipment resulting from the rebuilding effort following Hurricane Katrina and Rita. Of course, none of these delays have any impact on recoverable reserves.

First production from our High Island Block 165 #1 well is planned for later in the third quarter. It is expected to produce at a rate of approximately 60 million cubic feet of gas a day. In addition, we're currently drilling an offset development well from High Island 130. The well is drilling below 15,000 feet, for a total depth of approximately 17,000 feet. This new well is being drilled from the same surface location as the discovery well, so it should come on production fairly quickly. We own a 16.7% working interest, and Hydro Gulf of Mexico is the operator for both of these wells.

Initial production from our High Island Block 8540 #1 well is expected this month, at a rate of approximately 11 million a day. We own a 60% working here, working interest here. Walter Oil and Gas is the operator on this block.

Our first production from the initial test well in our Texas state waters project at Brazos Block 405 is expected later this month, at a rate of approximately 3 million cubic feet of gas a day. We own a 50% working interest here.

The East Cameron Block 268 #1 well is expected to begin production late in the third quarter, at approximately 15 million cubic feet of gas a day. We own a 50% working interest, and we operate this block.

And our Prairie Beach discovery, in Cameron Parish, we expect to begin production during October at a rate of approximately 12 million a day. We also operate this block, and we own a 75% working interest.

So far this year, we've drilled six wells, which resulted in four discoveries, one dry hole, and one well being abandoned before reaching its objective, that being the [Bob] North. In addition, we have two development wells drilling which were mentioned previously, and we also are drilling an exploratory well at East Cameron Block 109. That well is near in its target and should be down in the next several days. We own a 25% working interest in that block.

Before year-end, we plan to drill another three exploratory wells in Texas state waters, in addition to an onshore South Louisiana well. Our exploration program also includes three deepwater prospects, which we plan to drill in the near future.

On the deepwater side, our [Norman] prospect at Garden Banks 434 will test a large sub-salt structure. It contains an estimated reserve potential of 200 million to 500 million barrels. We plan to drill the initial well sometime in the next 30 days.

We're drilling approximately 28,000 feet. but should be at total depth prior to year-end. We have a 5% working interest.

Also in the deepwater, our Midway prospect, developing this Canyon Block 529, is expected to spud during the fourth quarter. Midway is a gas prospect, estimated reserves in the 200 Bcf range. If successful, it'd be tied back via sub-sea completion, to an existing facility on the shelf. Currently, we have 100% working interest, but we're looking for a partner and anticipate retaining approximately 50% working interest in the well.

Planning is also underway to re-drill our Bob North prospect, which should occur hopefully late this year, early next year. As most of you know, Bob North contains reserves in the 400 million to 800 million barrel range, and we have a 3.3% working interest.

As mentioned in our previous conference call, the Entrada, our deepwater discovery at Garden Banks 782--we continue to make progress with the engineering design study, which includes two wells, sub-sea tiebacks to ConocoPhillips' Magnolia TLP, located on the adjacent block. Again, we continue to anticipate first production there during early 2008.

Moving to the financial results, as I've mentioned earlier, the second quarter of 2006 production was not what we had hoped. However, we did exceed analysts' expectations for earnings per share by $0.02. Production for the second quarter of 2006 was on the low side of our guidance range, consisting of 443,000 barrels of oil, 2.6 Bcf of natural gas, or 58 million cubic feet, [inaudible] a day. This compares to our guidance of 62 million to 65 million cubic feet of gas a day.

The difference is due primarily to three wells. High Island 165, which we expected to come online in May, has been delayed due to services including pipeline barges and is now anticipated to be online in October.

West Cameron 295 #2, which we had anticipated acidizing and producing at high rates--instead, we've decided to produce at current rates, about 13 million a day. And at High Island 73, which we're producing at 10 million a day, instead of pulling it a little harder and trying to produce at 20 million a day.

Oil and gas sales for the second quarter in the six-month period ended June 30, 2006 totalled $47.1 million and $92.6 million respectively. Both increased from their respective periods last year, primarily due to pricing.

As discussed in previous conference calls, the spread between the benchmark oil price and our average realized oil price is due primarily to quality adjustments that occurred in the sale of our production from Medusa and Habanero, which accounts for approximately 90% of our oil production.

I refer you to our news release for the results of operations, the section of our Form 10-Q, for reconciliation of our realized oil price to the average NYMEX price. In addition to the quality adjustments, previously established crude oil hedging positions reduced our average realized oil price $1.59 and $1.14 per barrel for the three-month and six-month periods ended June 30, 2006.

Natural gas price realizations averaged $7.93 and $8.44 per Mcf, for the three-month and six-month periods ended June 30, respectively. Previously established natural gas hedging positions increased our average realized price by $0.96 and $0.79 for the three-month and six-month period ending June 30.

On the expense side, lease operating expense for the second quarter and the six-month period ending June 30 was $7.4 million and $13.3 million. Lease operating expense for these periods was higher than last year, due to increases in insurance, fuel and transportation costs.

G & A expense for the second quarter of 2006 was $1.9 million. It was below our guidance range of $2.1 million to $2.4 million. Interest expense for the second quarter was $4.1 million, and 3% less than the second quarter of 2005.

In addition, interest expense of $8.3 million for the six-month period ended June 30 was 6% below the same period last year.

Discretionary cash flow is a non-GAAP measure, and we have provided a reconciliation of same in our news release. Discretionary cash flow in the second quarter totalled $35.1 million, or $1.64 per share. This was an increase of $4.7 million, or 15%, from the second quarter of 2005.

Discretionary cash flow for the first half of 2006 totalled $68.9 million, an increase of $7 million, or 11%. The increases were primarily due to higher oil and gas prices.

Cash flow, along with borrowings of $7 million from our revolving borrowing base, was used to fund our capital expenditures and abandonment obligations. As of June 30, 2006, our unused revolving borrowing base was $63 million.

As discussed in the operations, initial production from five of our discoveries is scheduled to be later than we had forecasted earlier in the second quarter. This has resulted in a decrease of approximately 17 million cubic feet equivalent a day in our guidance for the second half of 2006, or approximately 10 million a day for the full year.

With that being said, for the third quarter, we're projecting production in the range of 51 to 55 million cubic feet equivalent per day, consisting of 43% oil. For the year, we're expecting average production rates between 58 to 62 million cubic feet equivalent a day, with 45% being oil. This represents a 19% increase over 2005 production.

Lease operating expense should be approximately $7.5 million to $8.5 million for the third quarter, and $28 million to $31.7 million for the full year of 2006.

G & A for the third quarter should be between $2 million and $2.3 million, and $7.8 million and $8.3 million for the year.

Interest expense for the third quarter should be between $3.8 million and $4.2 million, and $16.1 million and $17 million for the year.

With regard to depletion, we have set the range for $13.4 million to $14.8 million for the third quarter, and $61 million to $65 million for 2006.

We have approximately 75% of our gas hedge for the third quarter, and 61% hedge for the second half of 2006. Most of our production is sold in the general area of Henry Hub, which is comparable to NYMEX. We have collars in place in for the third quarter, with an average floor of $8.00 and a ceiling of $9.44. For the remaining six months of 2006, we have collars in place with an average floor of $7.81, and a ceiling of $10.07.

We have approximately 50% of our oil hedge for the third quarter and the second half of 2006. For outstanding oil hedges, we have a floor of $60.00 and a ceiling of $79.43. Please refer to our news release for the details on hedging.

Just a reminder that our realized oil prices will continue to be affected by quality differentials and transportation costs. Approximately 90% of estimated third quarter oil production should be from Medusa and Habanero. Approximately 85% of production for the second half of 2006 should be from Medusa and Habanero. We anticipate transportation costs should average $1.25 to $1.30 per barrel.

So with that, we will open the conference call up for questions.

Thank you. Ladies and gentlemen, if you would like to register a question, please press the 1, followed by the 4, on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered and you would like to withdraw your registration, please press the 1, followed by the 3. If you're using a speakerphone, please lift your handset before entering your request. One moment, please, for the first question.

Our first question, coming from the line of Ron Mills, from Johnson Rice. Please proceed with your question.

Morning, Fred.

Morning, Ron.

Was--let me get an easy one out of the way. The price differentials that you have in your Q, is that--$7.80 to $8.00, is that a good number to use going forward as well?

Yeah, it is, Ron. That'd be a good number to use.

Okay. And you walked through the five wells that have been delayed, one of which you talked about the actual delay being--instead of coming on in May, it's coming on in October. Can you walk through the other wells, in terms of when the original expectation was? Because it looks like you're--the implied volumes for your fourth quarter get back to somewhere in the 70-plus million a day range, to get your full-year target?

Yes, that's correct. And yet, as I've said, we're looking at just the continuing delays, and they're not--they're related to just a series of service-type issues, whether it's divers, or pipeline barges, and the--kind of running down them, I think, in our High Island A540, I think we originally we looking at July 15. We're now looking at kind of the third week of August.

Of course, I mentioned High Island 165, and we'd anticipated coming on end of May--we're now looking at kind of the first of October.

Prairie Beach, again, we had originally anticipated we'd be on in mid-August--we're now looking at mid-October.

And I think it, our [Blondie] prospect, we were originally looking at the first of August, and now we're looking at the first of October.

And how about Brazos 45? The late August? Is that about where you would have expected? Or is that delayed as well?

At Brazos?

Yes.

I think we're probably about a--originally thinking, maybe first of July, and now we're probably somewhere early- to mid-August.

Ron Mills. Okay. And from a current activity standpoint, you said you're drilling a couple of development wells, and one exploratory well at East Cam 109. The East Cam 109, can you walk through a little of the stats on that, and where are you drilling your development wells?

Yes. First, of course, on the development wells, I mentioned we're drilling at West Cameron 295, the offset to the #2 well, which is the #4 well. And we're--like I said, we're actually down on that, literally today or yesterday, and so we're in the process of evaluating that.

And then we're drilling at--offset from High Island 165, drilling a development well that's on the High Island 130. We're currently drilling below 15,000 feet, on our way down to approximately 17,000 feet there.

And then, I think I mentioned we're drilling at East Cameron. We're looking to see where we are on the East Cameron right now. I think we're--we should be down in approximately a week, a week to ten days, something like that. And this prospect, we've got a 25% working interest out here, we're--BP Oil is the operator. This is a prospect we had basically participated with them, they participated with us on a couple of different prospects, and I think we're looking at maybe a 25, 30 Bcf kind of target out here. Like that should be down in a couple of weeks.

And then, finally, the remaining drilling this year, I think you mentioned three wells--in Texas state waters, one well, and Louisiana, three deepwater wells. Any more shelf wells?

We--at the current time, we don't--we've got a couple that we're looking at, but we're just not sure if we're going to get--whether or not we'll have them ready by fourth quarter. So I would hope that by the next call we will have some additional drilling going on in the fourth quarter, but at this point, we don't have things finalized.

And so, your plan, then, would--looks like it will be somewhere on the order of 13 to 15 wells, depending on the timing of the Bob North and what not, correct?

Yeah, that would be--I think 15, and I think with the possibility of maybe a couple additional wells, but at this point, yes, I'd say 15.

Okay. And then, from a capital standpoint, your full year capital budget--does it still stand, from a drilling standpoint, close to $70 million with an additional--what's that--I'm sorry, I may be looking at--no, I'm getting the wrong--

That's right, yeah, no.

I'm getting the wrong numbers in front of me. But I have a drilling budget of $140 million of drilling, with an additional $15 million or so of capitalized costs, is that still the right number?

Yeah. Yeah, that's about right. And again, that just kind of depends on some exact timing as to when we might spot some wells, whether it's kind of, in December versus January. But yes, that's a good number for now.

Okay. Thank you, guys. Let me let someone else--

Okay. Thanks, Ron.

Thank you. Our next question, coming from the line of Scott [Lewis], from Lewis Capital Management. Please proceed with your question.

Thanks. Good morning.

Morning.

I just had a quick question on the Bob North prospect. Do you think the--I don't know, your previous two experiences, did you learn anything about the geology or--that would make you more confident that this well's going to make it?

Okay. Yeah, we certainly learned--as you know, we've got a small interest out here. We've got three major oil companies out here, with Shell, and BP, and Chevron involved, and with Chevron operating.

The answer is yes, obviously, we learned something. Understand, we're now going for the third time, which is obviously frustrating to all of us, but I guess I ought to tell you is that Chevron, as operator, we attend the meetings and they have got a large team focused on looking on what went wrong last time and how we can get it right this time.

And quite frankly, the reasons are long-winded and complex, having to do with salt, and how we approach it. But the answer to your question is, yes, we have learned something. Unfortunately, it took two times, and the two experiences, they were totally different issues. But hopefully we understand those now, and they're coming up with a plan that will let us get down on it this time.

Thank you. Our next question, coming from the line of Evan Templeton from Jefferies. Please proceed with your question.

Thanks. It's actually two questions, I guess, just relating to well performance. The first, I guess, is the High Island 73 #1, the well you decided to kind of cut back to 10 from--versus 20.

Right.

What did you see in the well that caused you to make that decision?

Just--I think we brought the well up, when we brought the well on at 10 million, the--I think it was more an issue of looking at the possibility of, if we pull it harder, that we might pull it too hard, and have sand problems out here. So it really just was more of a [Rushmore] management problem. There was certainly no change in reserves, and nothing has changed since our last call that would indicate at this point that there's going to be any difference in the reserves.

So--and I think it--the other one, I think we talked about was, at 295, I think, the #2 well, where we had planned to perform--were planning to perform an acid stimulation out here. I think we, after looking at that and doing some additional analysis out here, decided that we really don't think that acidizing the well would help that much, and we can recover the reserves from current production rates, and again, don't want to risk the sand production out here.

Okay, great. That's--those are my questions. Thank you very much.

Right. Thanks.

Thank you. Ladies and gentlemen, as a reminder, to register for a question, press the 1, followed by the 4. One moment, please. We have a follow-up question coming from the line of Ron Mills from Johnson Rice. Please proceed.

Fred, have you started to see any easing on the equipment and service delays, whether it's boats, or divers, or installers--has that started to improve a little bit, to increase the confidence level in the rest of the program coming on as expected?

I don't know that, to be honest. I can't say it's getting terribly better. I'll say, I don't think it's getting any worse. I think it will get better, and maybe we're seeing a little, but I think in terms of our estimates, I think we--the timing we're giving you now reflects specific timing of equipment and availability.

And so I feel, I feel good about the dates that we're giving you at this point. I can't say that--I'd have to say that it's still a bottleneck out there, in terms of whether it's trying to get a pipeline barge, or divers--I mean, there's--I'll have to say, there continues to be delays.

Having said that, I do think quite a bit of this, most of this perhaps, is a result of the hurricanes, and I do think there was a lot of pent up work, and I think as we sort of get through the year--assuming we don't have another major hurricane, yeah, I think we will continue to see things easing up, and I do think we're seeing quite a bottleneck of work out here that was the result of the hurricanes. So I do think it will continue to get better this year.

And then--it's still pretty early, but if we look ahead to 2007, can you walk through kind of what your inventory looks like, and how much--how extensive it is? Is it a one-year inventory, a two-year inventory? I'm just trying to get a sense in terms of the ongoing nature of the program.

Ron, right now, I'd say that our inventory when we--well, a couple of things. One, we are actively building inventory, we are--as we've talked before, our exploration strategy revolves around our acquiring 3-D seismic where we can obtain pre-stack time [inaudible] data, and use it to do some ABO work, help reduce some of the risk out here in the Gulf, and we're continuing to commit significant dollars to acquiring databases, working those. We'll be active at the lease sale here in August, working on lease sale for March of next year, so we're continuing to add, I think, and I think we'll--prospect inventory, quite frankly, is looking good in terms of finding databases, generating prospects, we're finding things that we like and we want to go after.

In terms of what we have leased today, I guess the answer would be, we have maybe up to a year inventory in terms of prospects, with the idea that prospects--obviously as we continue to generate new prospects, we put them sort of in the queue. And sometimes we'll slide prospects down, move other prospects up, depending on various things in terms of kind of where we are at the time.

So right now, I'd say maybe we have an inventory of prospects that may be--18 is a number, I'm just looking at our drilling schedule right now of prospects that we have that we could drill next year. But we're actively adding to that, and I think certainly by the beginning of next year, that number will increase significantly.

And is it more shelf-weighted in terms of prospects? Or is it spread pretty evenly between Texas state waters, Louisiana state waters, and South Louisiana?

I would say it is shelf-weighted. Clearly, our Alaminos Canyon way out there will be important in terms of--if we're successful out there, we've got quite a bit of follow up out there. And we've got a number of prospects, five or six prospects out there, that could weight things more towards deepwater if we're successful out there.

And then--sorry for taking so long, but--can you walk through the capitalized costs for the second quarter, G & A and interest?

Capitalized costs for the second quarter--the overhead was $2.1 million, interest $1.5 million.

And those are--are those good numbers going forward?

Yeah, I think they may increase some, but I think they are probably good numbers.

Okay. Thank you, guys.

[inaudible]--I'm saying, maybe, you might increase them by five, 5 or 10%, something like that, for the third and fourth quarter.

Okay. Thank you, guys. All right?

Thank you. Mr. Callon, there are no further questions at this time. I will now turn the call back to you. Please continue with your presentation or closing remarks.

All right. Once again, we appreciate everyone taking the time to call in, and as always, if you have any questions, please don't hesitate to give us a call. Thank you.

Ladies and gentlemen, that does conclude the conference call for today. We thank you for your participation, and ask that you please disconnect your lines.