Callon Petroleum Co (CPE) 2006 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Callon Petroleum Company fourth quarter and full year results conference call. During the presentation all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded Monday, March 12th.

I would now like to turn the conference over to Fred Callon. Please go ahead, sir.

Good morning. Thank you for taking time to call in for our 2006 year-end conference call. Before we begin the formal portion of our presentation I'd like to ask Terry Trovato, who heads our Investor Relations, to make a few comments.

Thank you, Fred. We would like to remind everyone that some of the comments made during this teleconference will be considered forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These comments, which include discussion of the Company's financial position, reserve estimates and business strategy, reflect management's views as of this date. No assurances could be given that these events will occur or that these projections will be attained. There are a variety of factors that may cause actual results to differ materially from the Company's expectations. Many of these factors are identified under risk factors in Callon's annual report on Form 10-K and other reports filed with the Securities and Exchange Commission. All forward-looking statements attributable to the Company are expressly qualified by these factors. It is also important to note that the SEC permits us in our filings with them to disclose only proved reserves that we have demonstrated by actual production or conclusive formation tests to be economically and legally produceable under existing economic and operating conditions. During today's discussion, we may use terms like reserve potential and probable reserves that the SEC's guidelines strictly prohibit us from using in our filings with them. These estimates are, by their nature, more speculative than estimates of proved reserves and accordingly, are subject to a substantially greater risk of being actually realized by the Company.

Finally, today we will be discussing 2006 cash flow, which is considered a non-GAAP financial measure. Reconciliation and calculation schedules for the non-GAAP financial measure were stated in our year-end 2006 results news release and can be referenced there on our website at www.callon.com for subsequent review. Fred?

Thank you, Terry. I realize there's a lot of interest regarding our acquisition of Entrada and we'll cover it in detail in a few minutes. But first we would like to review our 2006 results and 2007 guidance. Shortly after our last conference call in November, we announced that Bob Weatherly had joined the management team as Executive Vice President and Chief Financial Officer. Bob, as many of you know, has been a member of our Board of Directors since the Company went public 12 years ago, and has over 30 years experience in corporate financial management, investment banking, investment fund management and public accounting experience. We're excited to have Bob working with us and he has hit the ground running, particularly with the financing of our acquisition of Entrada. So before I review our operations and Entrada acquisition, I'd like to ask Bob to discuss our financial results for the final three months and full year of 2006, as well as the accompanying guidance for 2007. Bob?

Thank you, Fred. I'd like to take a few minutes now to discuss the results of operations for the three month and 12 month periods ended December 31, 2006. For the year ended December 31, 2006, Callon achieved record revenues, earnings, and cash flow from operating activities. We reported net income of $40.6 million or $1.90 per share versus analyst expectations of $1.81. This is compared to our previous record of $26.8 million or $1.28 per share for 2005. For the fourth quarter of 2006, we reported net income of $5.9 million or $0.27 per share, which met analyst expectations. For the same period last year, we had net income of $4.3 million or $0.20 per share.

During the fourth quarter of 2006, the Entrada Reserve reclassification raised the depletion rate, which increased charges by approximately $2 million net of tax or $0.10 per diluted share. Production for the fourth quarter of 2006 was 59.8 million cubic feet equivalent per day which exceeded our guidance range of 55 to 57 MMcfe per day. We produced 294,000 barrels of oil and 3.7 billion cubic feet of natural gas. This is compared to 224,000 barrels of oil and 1.2 billion cubic feet of natural gas, or 27.6 million cubic feet equivalent per day for the fourth quarter of 2005. For the year ended December 31, 2006, production was 1,634,000 barrels of oil and 11 billion cubic feet of natural gas, or 56.9 million cubic feet equivalent per day compared to 1,837,000 barrels of oil and 7.8 billion cubic feet of natural gas, or 51.5 million cubic feet equivalent per day for 2005. Total production in 2006 increased by 11% over 2005.

Oil and Gas sales for the fourth quarter of 2006 totaled $44.8 million compared to $24.9 million in the fourth quarter of 2005. For the year ended December 31, 2006, we had record Oil and Gas sales of $182.3 million, up by 29% from $141.3 million for the same period in 2005. Both increased over 2005 due largely to higher gas production and oil pricing, but also due in part to the inclement weather during the third and fourth quarters of 2005 resulting in down time. 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 incurred in the sale of our production from Medusa and Habanero, which accounts for approximately 83% of the fourth quarter oil production and 90% of our oil production for 2006. Please refer to our news release for a reconciliation of our realized oil prices to the average NYMEX.

In addition to the quality adjustments, previously established crude oil hedging positions reduced our average realized oil price by $0.61 per barrel for the year ended December 31, 2006. However, for the fourth quarter of 2006, the average realized oil price increased by $0.30 per barrel after hedging impact. Natural gas price realizations averaged $7.82 and $8.07 per Mcf for the three month and 12 month periods ended December 31, 2006, respectively. Previously established natural gas hedging positions increased our average realized price by $0.84 and $0.90 for the three month period ended and 12 month period ended December 31, 2006 respectively.

On the expense side, LOE for the fourth quarter was $7.5 million or $1.37 per equivalent Mcf of production, and in the middle range of our guidance. For the year ended December 31, 2006, LOE was $28.9 million or $1.39 per equivalent Mcf of production. G&A expense for the fourth quarter of 2006 was $2 million or $0.37 per equivalent Mcf of production, and below our guidance range of $2.3 million to $2.6 million. For 2006, G&A expense was $8.6 million or $0.41 per equivalent Mcf of production. Interest expense for the fourth fourth quarter and 12 month period ended December 31, 2006, was in the high end of guidance at $4.2 million and $16.5 million respectively.

Discretionary cash flow is a non-GAAP measure, and we have provided a reconciliation of the same in our news release. Discretionary cash flow in the fourth quarter totaled $32.9 million or $1.54 per share. This was an increase of of $21.3 million from the fourth quarter of 2005. Discretionary cash flow for the year ended December 31, 2006 achieved a record of $133 million, an increase of $39 million or 42% when compared to 2005. The increases were primarily due to increased production, gas production, and higher oil prices. Cash flow, along with borrowings of $35 million from our revolving borrowing base, were used to fund capital expenditures and abandonment obligations. As of December 31, 2006, our unused revolving borrowing base was $40 million.

I'll now take a minute to comment on guidance for the first quarter and the year ended 2007. We've incorporated the Entrada acquisition into our guidance and will discuss its impact on the affected categories. For the first quarter, we are projecting production in the range of 57 million to 60 million cubic feet equivalent per day, consisting of 67% gas. For the year, we are expecting an average production rate between 59 million and 64 million cubic feet per day, with 70% consisting of gas. This represents an approximate 8% increase over 2006 production. We had announced earlier this year that we expected the first quarter production to range between 62 and 65 MMcfe per day and 62 and 67 MMcfe per day for the year. However, the early water production at North Padre Island 913 and Prairie Beach, which will be discussed in the operations section, have negatively impacted our production guidance.

Lease operating expense should be approximately $9 million to $10.5 million for the first quarter and $29 million to $33 million for the year. First quarter G&A should be between $2.4 million to $2.6 million and $9.4 million to $10.4 million for the year. Interest expense for the first quarter should be between $4.2 million to $4.7 million and $31.4 million to $34.8 million for the year. The increase in projected interest expense after the first quarter is due to the anticipated interest expense associated with financing related to the Entrada acquisition.

With regard to depletion, we set the range at $20 million to $22 million for the first quarter and $72 million to $80 million for the year. The decrease in depletion after the first quarter is due to the inclusion of the Entrada acquisition and our depletion calculation which lowered the depletion rate. We have approximately 45% of our gas hedged for the first quarter and the year. Most of our production is sold in the general area of Henry Hub, which is comparable to NYMEX. We have a collar in place with a ceiling of $12.70 and a floor of $8 for the first quarter and the remainder of 2007. We have approximately 51% of our oil hedged for the first quarter and 53% hedged for 2007. For outstanding oil hedges, we have collars with an average ceiling price of $88.75 and a floor of $65 for the first quarter and the remainder of 2007. Just a reminder that realized oil prices will continue to be affected by quality differentials and transportation costs. We anticipate transportation costs should average about $1.15 to $1.24 per barrel.

Thank you, Bob. Now let me review status of our major fields to just give you an update. Medusa is currently producing 15,900 barrels of oil and and 16.5 million cubic feet of natural gas a day. As we discussed on our last conference call, the A-1 well developed a mechanical problem in the fourth quarter of 2006. We now know that the problem was related to a leaking plug between the current completion and a deeper abandoned completion in the T-4 sand. We were concerned at the time that we would need to perform a lengthy and expensive rig work-over to solve this problem, but we were ultimately able to restore production using wireline equipment, although at a reduced rate. The well was making approximately 9,000 barrels of oil a day before the problem, and 3,500 barrels of oil a day now. This should not affect ultimate recovery, and we are well pleased with how the field is now performing. We own a 15% interest in the Medusa field.

Current production from Habanero is 6,200 barrels of oil and 9.2 million cubic feet of gas a day. The rate continues to decline due to the strong water drive in the reservoir from which the Number Two well produces. We anticipate a sidetrack of the Number One well up dip of the two existing Hab 52 completions to begin in mid May, with first production in October. This sidetrack should increase field production to 16,000 barrels of oil and approximately 24 million cubic feet of natural gas a day at that time. We own 11.25% interest in the Habanero field. Production from High Island 165 Number One well is currently 42.5 million cubic feet of gas and 200 barrels of oil a day from a single completion in the sand, known locally as the Gyro K-1.

We've drilled an offset development well on High Island Block 130 which encountered additional pay below the initial discovery sand, and is currently being completed. The well of the High Island 130 Number One is expected to commence production this month at a rate of 35 million cubic feet a day of gas and 175 barrels of oil per day. A third well, the High Island 130 Number Two is currently being drilled to develop the deeper reserves and test an additional section for still deeper pays. Callon owns a 16.7% working interest in the Gyro K-1 and 11.7% interest in the deeper sands. We anticipate first production from the High Island 130 Number Two well to begin in the third quarter of 2007, and expect total field rate at that time to be approximately 120 million cubic feet of gas and 500 barrels of oil per day. These wells are operated by [Hedro], Gulf of Mexico.

At North Padre Island Block 913 Number One, we're producing at a rate of approximately 13.8 million cubic feet of natural gas a day, down from 15.4 million a day during our last quarter. The well has started producing water from a strong water drive reservoir. We operate on a 50% working interest. The West Cameron Block 295 Number Two well is producing at a rate of 12.5 million cubic feet of gas a day and 70 barrels of oil a day. And the Number Three well is producing at a rate of approximately 11 million cubic feet of natural gas a day. Both are unchanged since the last conference call. We have drilled an offset to to the Number Two well, the Number Four, which has commenced production at a rate of 4.4 million cubic feet of natural gas a day. This is less than the rate we had expected because the completion is in a thin, lower rob M1 interval, below the main rob M1 pay. Upon depletion of this lower reservoir, the well will be recompleted to the original exploratory target, the upper rob M1, where we expect a rate of 10 million to 12 million a day. We own a 20.5% working interest in the block and the Number Two and Number Four wells are operated by Hedro. Number Three well is operated by Cimarex.

Our High Island Block A-540 Number One well is producing at a rate of 8 million cubic feet of gas and 300 barrels of oil per day, higher than the 6 million cubic feet and the 190 barrels of oil at the time of our last conference call. Callon owns a 60% working interest and Walter Oil and Gas is the operator of this block. The East East Cameron Block 268 Number One well is currently producing at a rate of 8 million cubic feet of gas equivalent per day. We own a 50% working interest. And our East Cameron 109 Number Five well is producing at a rate of 9 million cubic feet of gas and 200 barrels of oil a day. Energy Partners operates and we own a 25% working interest. Our Prairie Beach discovery in coastal Cameron Parish, Louisiana, is producing 8.5 million cubic feet of natural gas and 250 barrels of oil per day. The well is being choked somewhat to control sand and water in this non-gravel packed completion. We own a 75% working interest and operate.

Our L.J. Miller Pumpkin Ridge prospect, located onshore Louisiana, should commence production in April. We expect it to produce at a rate of 11 million cubic feet of gas a day. We own a 10% working interest. The well is operated by Red Willow. In the fourth quarter. we reached total depth at our Norman prospect in Garden Banks 434. The well did not test its intended objective, and while consideration was given to sidetracking, the well was ultimately plugged. The partners are currently evaluating the results of this well and may plan a second attempt in the future. Callon owns a 5% working interest. In our Midway prospect at Alaminos Canyon, Block 529 was drilled in the fourth quarter and was unsuccessful, encountering gas saturation and poor quality reservoir. Midway was the most remote, but largest target in this package, and we elected to make it our first drill well. While we were certainly disappointed with the results at Midway, we have under lease an additional seven prospects in the East Breaks and Alaminos Canyon area. And while the result at Midway will have some bearing on a couple of these prospects, most remain unaffected due to nearby sand ties. Callon has a 50% working interest in Midway and 100% in many of the remaining prospects.

After drilling Midway, the rig was moved to our DeMont prospect on Green Canyon 732. DeMont came to us in trade for a portion of Midway, and it too was plugged and abandoned for encountered shows, but no reservoir quality [rot]. We have a 25% working interest. We're currently drilling our Mud Island prospect in Cameron Parish, Louisiana. Mud Island is a 40 Bcf lower Miocene AVO target which was generated as part of our Transition Zone Initiative. Last week a drilling liner which -- was set at about 16,140 feet. We should be drilling out within the next day or two. Proposed total depth is approximately 19,000 feet. We expect to have this well down by the end of the month. We own a 15% working interest in this prospect.

In the Deepwater area, we have recently received and executed an AFE for the drilling of the Bob North Number Three well. As most of you are aware, we have previous two attempts to test this prospect and they've resulted in [junked] wells associated with salt entry and exit points. Considerable planning has gone into the latest well design to ensure a successful test of the objective in this next well. Reserve potential at Bob North is in the 400 million to 800 million barrel range, and Callon owns a 3.3% working interest. The well is expected to begin drilling in the third quarter of this year.

Overall, in 2006, we drilled a total of 17 wells, eight of which were successful. Those eight wells added a total of 15.8 Bcfe of proved reserves, but more significantly, a total of just over 30.3 Bcfe proved and probable. Majority of the probable reserves are associated with seismic anomalies that extend beyond the current lowest known oil and gas level. For 2007, the Board of Directors has adopted a capital budget of $125 million, which includes an active exploration program, currently with 17 wells scheduled to be drilled this year.

Now let's talk about Entrada. As I'm sure you're aware, we announced last Thursday night that we have signed a purchase and sale agreement with BP to acquire their 80% working interest in the Entrada field. This is a landmark transaction for our Company and the largest in its history. It builds upon our proven Deepwater track record, allows us to take control of an asset that we've been working on for many years, and have a very good understanding of, from a technical and operational standpoint. Most importantly, it has very compelling economics. As stated in our news release, the purchase price includes $150 million payable at closing, and additional $40 million payable after the achievement of certain production milestones. The purchased interests include five federal offshore blocks, a Garden Bank blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. Upon completion of the acquisition, Callon will own 100% working interest in the Entrada Field and will become operator. The acquisition is expected to close within the next 45 days.

What we will acquire is an 80% working interest and a 70% net revenue interest in 35.7 million barrels of oil equivalent gross, or 25 million barrels equivalent net, yielding an acquisition cost of $7.60 based on the $190 million cost. With total development costs of an additional $200 million for the purchased interest, the fully developed cost is $15.60 per barrel. We've already been in touch with ConocoPhillips, operator of the Magnolia TLP, and plan to move forward with production handling agreement discussions immediately. As you may know, these discussions are well along, and our expectation is that they can be finalized in the near future. We have a good working relationship with ConocoPhillips people and look forward, as operator of Entrada, to working with them.

Our initial development plan for Entrada is to drill and complete two wells, both as subsea tie backs to the Magnolia TLP, and to make provisions for future wells to be brought in through the same infrastructure. Each well should be capable of flowing 15,000 barrels of oil and 50 million cubic feet of gas a day. However, our ability to flow these rates will be dependent on available capacity at the host platform. While we expect to have some level of firm capacity at Magnolia and all of our economic models assume there will be rate limitation, we plan to work closely with the operator to ensure that spare capacity is used as it becomes available.

At this point, we expect to be able to bring the first Entrada well on production in early 2009, with a second well to follow later in 2009. We've already begun the process of locating a drilling rig. While it is not easy to find a deepwater drilling rig, we are confident that we will be able to contract a rig to drill our two wells sometime in 2008. While many rigs are under long term contracts, operators often have scheduling issues and rig slots become available for enough time to drill one or two wells. For example, in our search for a rig to drill Midway, we were twice offered rig slots by other operators whose plans had changed. In addition, there are a number of potential industry partners who have rigs under contract, and that we feel would welcome the opportunity to participate with us in the development of Entrada.

To finance the acquisition we've received a committment from Merrill Lynch Capital Corporation to make available to Callon a seven year $200 million revolving credit facility secured by first lien on the Entrada Assets. The financing package provides flexibility by funding not only the initial purchase price, but also providing additional funds for long lead items necessary to keep the project on track. This allows us to move Entrada forward without impacting our drilling plans elsewhere.

All that being said, let me make it clear that we have no intention of maintaining this high debt level or developing the field on our own. We feel that we have a great asset which we now control, and we intend to seek either a financial or industry partner, which will allow us to reduce our debt level and to participate in the development of the field, as well as explore the additional upside potential we see on the blocks. So with that, I'll now open the conference call for questions.

[OPERATOR INSTRUCTIONS] Ron Mills, Johnson Rice.

A couple questions on the Entrada transaction. Can you just -- or where you stand with negotiations, can you update where you are with negotiations on production handling agreement? Because I know you and BP have marched quite a ways down that path. What are some of the remaining issues?

Sure. Ron, as you know, I've mentioned in conference calls, the last several conference calls, that we have been involved in the negotiations for the production and handling agreement with ConocoPhillips and Devon. Obviously to date, BP, as operator, has been leading those discussions, and they've done a great job moving them forward and negotiating many, if not most of the points in -- that will be contained in the production handling agreement. And so we have been involved in all of those meetings, obviously, not only with our staff, but with our counsel. So we feel like that we're going to be able to pick up the negotiations very smoothly and move them forward. We've already been in contact with ConocoPhillips, talked to them, and are already scheduling meetings with ConocoPhillips to move those negotiations forward.

So while we do have some additional points that we do need to negotiate and work out with ConocoPhillips, we feel like that we're going to be able to get the production handling agreement finalized in the fairly near future. We don't want to put a date on it because -- until we had an opportunity to sit down with ConocoPhillips. But certainly, I think in the next several months we should be able to hopefully, depending on the time schedules and availability of people, be able to bring the PHA discussions to conclusion.

And in order to meet an early 2009 start up, is there a point in time where you need to have the PHA signed and the development plan finalized in order to meet that time frame?

No. In fact, I don't think that's really in the critical path. I mean, again, we're confident that we have understanding on many of the basic issues with ConocoPhillips. And right now, we're moving forward with engineering, and that's really not going to be critical path. Again, from our standpoint, we're -- kind of the important steps are to now start working on the final engineering. And that's what we're kicking off and have already started the first meeting on Friday. Preliminary engineering work had been done with consultants with BP and Callon involved. So we're moving forward with that so that we can get some of the long lead items ordered, and that's really sort of critical path to first production in early '09.

Okay. And what's left to finalize beyond the preliminary engineering work? Like, what's the next step in the engineering design?

Well the -- again, kind of going back, BP had, of course, was operator. And so we're going back, and they did, I guess the preliminary front end engineering design work. And we're now doing, if you will, the more detail-specific engineering work that -- that will be going on here really during the kind of second and third quarter. And then coming out of that, we'll be ordering the long lead items, identifying the specific technical parameters for some of the long lead items that we need, and trying to see if we can find a way maybe to accelerate the time frame in getting some of those ordered. And so that's really sort of the timing. But right now, I guess we're thinking second and third quarter doing the detailed engineering, ordering long lead items, and some could be in some time in the third quarter, early fourth quarter, some of those could be as much as 12 months. Again, we just need a little time here to-- over the next couple months, we'll be, obviously as operator, be focusing on that and seeing what we can do to be sure that we can meet that -- not only meet that time frame, but hopefully see what we can do to maybe try to accelerate it a little if possible.

Okay, and then on your shelf program, the 17 wells you're planning, is the hope there to basically be able to keep your production flat to maybe even slightly grow it over the course of '07, '08 as you head into the '09 time frame where you'll have a big increase from Entrada?

Absolutely. I mean, that's obviously what we're trying to do. And production in 2006, certainly up over 2005, and certainly we plan to have production -- our goal is to have production in 2007 show an increase over 2006. And then obviously, if we can continue that on into 2008, when 2000 -- we see the production coming in from 2009, Entrada is going to be obviously a significant increase.

Okay. And is the '07 program significantly different from a risk profile than '06, when you were eight of 17?

No. I don't think so. As I kind of look through it, no. It's fairly similar.

And then one more if, I may, and this would be a cleaning up for Bob. You walked through the DD&A, the full year. You mentioned why the remainder of the year is going to be lower than the first quarter. Is there also -- do you have a similar reason for the LOE? Because it looks like your LOE in the first quarter is a lot higher than the run rate that the full year would suggest.

No, Ron, not in particular.

Okay. Thank you.

Evan Templeton, Jefferies & Co.

Can you just give us a little bit more color on the nature of the Merrill Lynch facility? Is it kind of one traunch of revolver? Or is it two? And also, what sort of pricing? And also, just is that facility non-recourse? Or, if you can just give us more color on exactly what it is.

Sure. It will be sort of one traunch, if you will, with the $200 million, as we said sort of seven year note. It is recourse, secured by the Entrada assets. And the $200 million, as we indicated, will give us the funding to acquire $150 million for the initial payment to BP, as well as give us an additional $50 million for debt service and for ordering long lead items if needed, and so that we can continue our exploration budget, if you will, as we had planned. Pricing is still to be determined. We basically -- what we have is a committment from Merrill with back-stop pricing, where they have made a committment to us. We will be syndicating the financing in the next 30 days. And so the financing -- specific term -- rates will be determined at that point. And so we'll obviously have that information disclosed here in the next 30, 45 days.

Great. Thanks.

Sure.

And then just one other question. On your capital budget that you mentioned for '07?

Yes.

Is there any spending on Entrada in that?

There's -- no, we don't anticipate any -- not in the CapEx. And again, that's something we're looking at now. But certainly don't anticipate any significant spending on Entrada this year. The money we're spending is going to be on probably engineering studies. And to the extent that we're required to -- if -- some of the -- ordering some of the long lead items, to the extent it requires some deposit, there may be some spending. If it is, it's in the fourth quarter, and that's part of the reason we, like I said, we got the additional $50 million financing on the -- with Merrill Lynch, in the case we do need additional funds in the fourth quarter to begin ordering long lead items.

Okay. Fair enough. Thank you.

Philip Dodge, Jefferies & Co.

First, I'm wondering if you could go through the engineering issue that led to the reclassification of some of the Entrada reserves to probable from proved undeveloped?

Sure. Is this, I'm sorry, Phil?

Yes.

Okay, yes, the change in reserves at Entrada was -- this was our third party engineer in our year-end reserve report. He decided to reduce the proved reserves based on performance he had seen in some analogous reservoirs during last year. Obviously, in Deepwater he had been looking at some reservoirs, had seen performance, I guess, at what -- this is, what, '07 -- I guess during 2006, during the last 12 months, and felt like based on recovery factors he was seeing there, that he needed to reduce the recovery factors that he had been using before. So that's what drove that decision. And like I said, it's unrelated to, and just coincidence that it occurred at a time when we were making this acquisition.

And what are the circumstances under which those reserves could be reclassified back to proved from probable?

I think it -- I think really production, as we bring the wells on and start seeing production out here. And once we get some production performance and, quite frankly, to the extent that we can demonstrate the -- that we are in fact achieving higher recoveries, that's what's going to help, for the most part, drive higher reserves.

So that would take probably a couple years of production history?

Yes, again, I don't want to pin him down. But I would certainly think that you need a year or two of production history I would think in order to demonstrate that.

Okay, and then just from the income statement estimating side, will any of the interest related to the development of Entrada be capitalized?

Hold on, Phil. Just a second. The question is the interest on Entrada. Will that be capitalized?

No.

No, it will not be.

Okay. Certainly didn't see that in the guidance.

Right.

Okay. Just want to make sure I understood completely.

Yes, I just wanted to make sure I was right.

Okay, thanks very much.

Lawrence Flood, Wellington.

I had some questions about Entrada, as well. I think they're largely answered. But how about the capital spending for Entrada in 2008 as opposed to '07 and for '09, as well. And I was kind of wondering if down the road a bit, you could give us some idea of the present value associated with the Entrada situation, given the fact that in 2005 it amounted to -- even your lower interest amounted to practically $500 million.

Larry, first, on the development cost. We're -- right now we're looking at a total of [8-8] $250 million development cost, which would include laying flow lines, umbilicals, trees, tying back to the Magnolia TLP, and also including the drilling and completing of two wells. We're looking -- all of that, we're looking at $250 million. And we're working on some of the detail engineering now that will really drive a little more specific timing, but certainly anticipate those costs would be incurred beginning sometime maybe by second quarter to third quarter of next year going on through the first quarter of 2009. Approximately that time frame is when I think most of the cost would be incurred. With respect to the present value, I think the Entrada PV-10 at 12-31-06 was $453 million -- .

Current pricing.

-- and based on current pricing, that number is about $623 million.

Okay, thank you.

Stephen Beck, Jefferies & Co.

Just a couple of questions.

Sure.

Will you be putting together all of the financial projections for Entrada when you complete the credit facility?

I'm sorry, I didn't quite understand.

I'm sorry?

I didn't understand the question. Excuse me.

I'm wondering if you're going to be putting together all of the financial details, or the projections, the forecasts with the timing of the credit facility?

Yes, certainly, absolutely, we will.

And will you be making that public, that information public when that occurs?

Yes. Certainly. No reason not to, sure.

Okay. And then lastly, just thinking about the rigs for Entrada, are you going to require specialized rigs? Or what type of rig will you be looking for?

Yes, I think as far as the special -- it will typically be I guess what's referred to as Generation Four or Five rig to drill in these water depths and the depth that we're looking at out here. So, it's certainly going to require a rig like that. And as we said earlier, I think we recognize that's a bit of a challenge. But at the same time, as I said, at least our experience recently has been that if we can get ourselves into position and have some flexibility, which I think we have now since we operate and can control timing, that we can be in a position hopefully to take advantage of of a rig slot as it becomes available with another operator who may have a temporary opening, if you will, for 90 days or so.

Sure. Okay, great. Thank you.

Ron Mills, Johnson Rice.

To clarify on Larry's question, the PV-10 of $450 million at year-end prices and 623 at current pricing, that's for the full [8-8 sensors], correct?

Yes, Ron, I'm sorry. That was to the acquired interest, to the 80% interest. I thought that was his question. Is that what you were saying, Ron?

Okay, so that $453 million of PV-10 only represented the 80% interest?

That's exactly right. Yes, that was, again, the acquired interest, correct. Which is the 80% working interest.

Right. And then you mentioned the transportation cost on the oil side. Can you walked through also the rest of your oil and price differentials, because I know you have a pretty wide differential on oil prices, just what we should be running?

Yes, I'd be glad to. And Ron, we're looking for it. But it should be -- it's fairly similar, almost the same as last year. I'm just pulling it up here so we can give you some numbers. But it shouldn't be too different.

Yes, you talking for the full year, Fred?

Uh-huh.

The full year, the basis adjustment was $7.03, transportation was $1.25, and hedging was $0.61, reduction in average NYMEX -- from average NYMEX of $66.22 to a net realized of $57.33.

Okay, so the basis should remain around $7?

Yes.

And the transportation, I think you said should still be around $1.25 plus or minus?

That's correct.

And then on the gas prices, are you still getting roughly NYMEX, or do you get a little bit of a discount?

Pretty much we get NYMEX.

NYMEX.

Uh-huh. Yes, NYMEX.

Okay, and can you walk through the capital budget, the $125 million? How much of it is drilling, how much is capitalized interest, how much is capitalized G&A?

Yes, I'd be glad to. I think, again, leasehold and seismic is about $15 million. I think the capitalized overhead interest, $18 million.

So about $92 million drilling?

Yes. 93. 92.

Yes, that's correct.

And the capitalized interest in G&A is a little bit higher than it's been running in the past, I think is was around $12 million. What's that related to?

Just I think higher inventory level, I guess. Is that right?

Yes.

But should the split still be roughly three-quarters of that towards G&A and a quarter to interest? Or do you not have that breakdown?

Yes, I do. I think that's about right. I'm trying to think -- yes, about a third interest.

Right.

About a third interest and two-thirds overhead. Is that right?

Uh-huh.

Okay.

Okay, thank you.

Evan Templeton, Jefferies & Co.

You guys are obviously taking on a fair bit of debt, and you mentioned your desire to reduce that as quickly as possible. Can you just talk a little bit more about how much you -- or what you think that the proper amount of debt for the Company to have is? And kind of what the prospective timing might be and -- in terms of bringing in a partner?

Sure. I guess the deciding part, at least for us with the Merrill Lynch financing is that it allows us to finance this without having to sell equity now, because we think we've just got a lot of upside potential here over the next year or two. And so we recognize that this is a significant amount of debt, but as I've tried to point out, that we love Entrada a lot. We're very excited about the opportunity here. But we also recognize that this is not something that a Company our size can do 100%. So the real value we see here is being able to sort of control this, the timing of moving this forward. This is a project obviously we've been working with, living with for over six years. So we think it's a project that any number of industry and perhaps financial partners would love to participate in with us. And so with that in mind, we feel like that we'll be able to bring in a sufficient amount of cash to allow us to reduce this debt level, and we expect that to happen this year.

Kind of going forward here, it's certainly our plan to move forward with our -- get our production handling agreement finalized, and move forward with our detailed engineering work, and so that we've got the development moving forward. But at the same time, we'll certainly be out in the next several months. We will start to talk to potential partners, and I'd like to think that we will have a partner certainly by the fourth quarter of this year. And again, I think that will allow us to, like I said, not only reduce the debt level, but then obviously have a partner in for anticipating development cost going forward. As far as what debt level, that's a function of a number of things, in terms of where the Company is in terms of development versus exploration activities. But certainly, we've looked at targeting a debt-to-capital ratio down below 40% and would like to see it get down in the 35% range. And again, not using any one particular statistic, but I mean, longer term. But at the same time, we think that the opportunities like this for a Company like Callon, we think it makes a lot of sense to use leverage in order to take an asset like Entrada and move it forward. And so if that requires us to have a higher debt level for some period of time, we think it makes a lot of sense, in order to capture the value of an asset like this.

And do you have kind of a rough target of how much cash you might like to bring in, just real rough? I mean, is it 50 million -- ?

No. I think, I don't. But certainly, we're looking at bringing in a significant amount of cash that would allow us to help reduce a significant portion of the financing that we're doing here with Merrill Lynch. So we're not talking $50 million. We're talking about a number significantly higher than that.

Fantastic. Great. Thank you very much.

Kevin Smith, Raymond James.

I had a question on your recovery factors reduction for the Entrada field.

Sure.

Were the same recovery factors then used at the BP's interest of the field? What I'm trying to get to is in a year from now, if they had a different recovery factor, are we going to have to writedown some of those reserves that you purchased?

I'm not sure I'm following what you're -- I'm sorry, just repeat the question?

The recovery factors that were looked at on your 20% of the field?

Correct.

Were those the same recovery factors that were used in estimating BP's reserve interest?

Oh, yes. Oh, absolutely. Yes. I'm sorry, yes. Oh yes, no , we're not looking at -- I follow what you're saying now. No, absolutely, those were the same recovery factors, so yes.

Okay. And that's really all I had.

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.

Again, we appreciate everyone taking time to call in. Obviously, we're very excited about Entrada. And as we move forward here over the next 30, 45 days, once we get the acquisition closed, we'll certainly be providing that information to everyone. In the meantime, if anyone has any questions, please do not hesitate to give us a call. Thanks so much.

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