Exhibit 99.2
Spinnaker Second Quarter Earnings Conference Call
August 2, 2005
C: Roger Jarvis; Spinnaker Exploration Company; Chairman and CEO
C: Unidentified Corporate Speaker; Spinnaker;
P: Joe Allman; RBC Capital Market; Analyst
P: Kim Pacanovsky; KeyBanc Capital; Analyst
P: Ryan Zorn; Simmons; Analyst
P: Irene Haas; Sanders Morris Harris; Analyst
P: Michael Scialla; A.G. Edwards; Analyst
P: Phil Pace; Credit Suisse First Boston; Analyst
+++ Presentation
Operator: Good day and welcome to today’s teleconference. (Operator instructions) I will now turn the program over to your host, Mr. Roger Jarvis.
Roger Jarvis: Thank you, Leo and we thank you all for dialing in. Certain statements in the conference call are forward-looking and based upon Spinnaker’s current belief as to the outcome and timing of future events that are subject to numerous uncertainties. Important factors that could cause actual results to differ materially from those in the forwarding-looking statement include the timing and extended changes in commodity prices, operating risks, and other risk factors as described in our annual report on form 10-K for the year ending December 31, 2004 and our other filings with the SEC.
Should one or more of these risks or uncertainties occur or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in the forward-looking statements. The forward-looking statements in this conference call are made only as to the date thereof and we undertake no obligation to update such forward-looking statements.
Thank you and welcome to the Spinnaker second quarter conference call. We announced financial and operating highlights last night and we announced a truly outstanding quarter in every respect. Our EPS is $0.68 on a recurring basis, which beat the consensus pretty handily of $0.47. That was driven by higher production, lower DD&A and higher commodity price.
Revenue and cash from operations were both records for the company at $92 million and $80 million respectively for the quarter. Production of 13 Bcfe grew 10% sequentially and exceeded guidance of 12.3 Bcfe, and that is largely a product of the ramp up at Front Runner and better than expected performance across much of the portfolio.
Mid-year reserves were announced as well. Again, we do these reserves on a fully prepared basis
through Ryder Scott twice a year. I believe we are now the only E&P in the space that do reports on the outside twice a year. That report shows total adds of 91 Bcfe in the first half, production of about 25 Bcfe and an ending mid-year total of 373 Bcf reserve. That is up about 22% from year-end. Production replacement ratio of 370% in the first half led to a decline in DD&A of approximately 8%. Both welcome numbers. The discounted value of our Ryder Scott P1 reserve is now $1.6 billion on flat pricing. Price is actually up since those numbers were run.
We also had excellent exploratory results in the quarter, three new discoveries. We had previously announced the “Q” discovery of Mississippi Canyon 961, and that is a significant new deepwater find for Spinnaker. We will talk a little bit more about that. But we made also two very nice Shelf finds as well during the quarter. Galveston Island 210 or the Batters Box prospect was drilled during the quarter. We booked to about 6 Bcfe. However, we believe that is a 25 Bcf or so find. It is a hydrocarbon indicator base prospect.
Likewise, at West Cameron 295 we have made a very nice discovery. That prospect is called Fast Ball. It is located on the fringes of the hottest clay in the Gulf of Mexico, on the shelf and we will talk more about that. It was not booked during the quarter. We believe that resource is probably 30-40 Bcf, although probably not all that would be booked initially. We think we would get it pretty quickly through production performance. So those are both pretty nice finds by today’s standards on the Shelf.
We also announced the sale and leaseback of the Front Runner Spar Facility at 25%. That is a very favorable financing. It adds a piece of longer-term financing in our structure, created $75 million in cash and kudos to Robert Snell. That has been an ongoing saga and very favorable, we are glad it is closed.
We also announced that we should see our budget, our budget has increased to $310 million for the year. That is due primarily to incremental success in the exploratory program and incremental development expense forecasted. Also some cost escalation is being seen as well. Our realizations from unit product sales escalated 19% year over year, to in excess of $7 per Mcfe.
Turning to our reserve report. Certainly, the outcome for our mid-year report is certainly one of the best results from the sector. Again, we are one of the very few that do mid-year reports, but we are also one of the very few reporting unit DD&A reductions in the face of increasing costs environment and what we think is diminishing prospect inventory within the industry.
I think this 8% reduction is a welcome move downwards, but I think it points to, it is hopefully the first point in the process of lowering our DD&A and improving, I think, the depth of inventory that Spinnaker holds.
We feel that we have got a really deep bench in terms of prospect inventory better than I have ever seen it at a company. We think we have four or five very good years in front of us based upon the inventory we already own. We did book some reserves this quarter at both Thunder Hawk and at “Q”, also at Galveston 210. We think there are significant volumes yet to book at each of those properties, however. Thunder Hawk, we believe is booked to about a third, maybe
as much as half of the probable ultimate resource we have booked into the low 30 million barrel number. We continue to believe that is a 50-150 million barrel resource and we will see additional drilling on Thunder Hawk this year.
“Q,” we believe is booked to about 60-65% of its very demonstrable size. This is a hydrocarbon indicator based prospect. We have very good control on how big that resource is likely to be, but the vagaries of the definition put us in about the 90 Bcfe range, we think it could approach 150 Bcfe very easily.
Galveston Island is booked to about a quarter of what we think is a probable reserve of 20-25 Bcf, and again, we didn’t book at West Cameron 295. So the reserve numbers are great for the first half, but we think there is more to come on those properties over time.
In terms of exploration, we probably have as good a line-up as we have ever had and we are pretty excited about it. We had a terrific first half; six of seven wells were successful exploratory wells. “Q” is a very promising find, as we have alluded to, probably 140-150 Bcf. We drilled this well with a very high-priced rig, a very capable rig, the Cajun Express, but with a high day rate, and we were criticized at that time for that decision. I will say that it was a very good application for that rig. We don’t like high day rates, but this was a particularly good application: A well that had a lot of casing points, a lot of potential downtime and it was a very good application for a multiple operation rig like the Cajun Express.
The result was a record well for the Eastern Gulf. We TD’ed the well for $13 million. We actually drilled, evaluated, side-tracked, evaluated, cased the well and TA’ed for what was the original AFE to just drill and case the well, $24 million. So it was a very good outcome operationally. Additionally, we did that during peak storm activity at the time, a very difficult storm environment and also peak loop current activity. There was almost no down time on that rig.
So the economics now go like this for “Q.” $75-85 million all in finding and development costs, including the costs incurred to date. Considering only our P1 Ryder Scott reserve, we have finding and development costs of less than $1 per Mcf and with the probable resource that, again we feel very confident about, it would be less than $0.60 per Mcfe.
So low finding costs, high rate of return even with first production not coming until 2007, we have a rate of return on this project projected to be approaching 100%. We will go to the independence hub with “Q” along with the other original finds, Spiderman and San Jacinto in the Eastern Gulf.
Galveston Island 210, again, a good Shelf find, the second well on the block, our second successful well. We now think total resource on that block is in excess of 30 Bcf. We are booked to about 10 Bcf on the two wells. Both were drilled high on structure so we will get, we believe, increases in those booked numbers with performance.
West Cameron 295 is part of a very, very hot trend on the Shelf and one in which Spinnaker is very well situated. I want to talk a little bit about this. West Cameron 295 found 150 feet of pay in the lower Miocene interval, we think again probably a 30-40 Bcf discovery. But the lower Miocene trend in general in West Cameron is just a pretty exciting and quickly developing clay.
The trend itself really spans the whole West Cameron addition, east to west. It is a clay that has seen very high exploratory success rates. And of the seven rigs that we currently have operating, two of those rigs are operating in that trend. Those two wells are West Cameron 39, in which we own a 47% interest. That is a 100-200 Bcf prospect; it is a very large four-way closure. We have had it under lease for some time. We also had shallow production on that lease.
We have taken a partner for a small amount of our incremental interest, so we are on a favorable basis for the drilling of the well. The well is going to 21,700 feet. The other well in that clay that is currently drilling and also operated by Spinnaker is West Cameron 98. We own a 50% interest in that prospect. It is a 30-40 Bcf prospect and we are paying about a third of the drilling costs to 17,500 feet.
Other wells that are currently ongoing, we are drilling High Island 197. That is a Rob M Test, Rob L, Rob M going to about 14,000 feet. The main objective is Rob L5. We think it is a very low-risk well with a great chance of finding 30-35 Bcf. It is being drilled at a platform location so it would be near-term production as well.
High Island 200 is an 11,400-foot test currently operated by Spinnaker, currently in the drilling stage. We own a 65% interest in that prospect and it is again, about a 30 Bcf objective.
We are also drilling the Egmont Prospect, Mississippi Canyon 413, and we currently have 100% interest in this prospect. The well is going to 14,000 feet. It is situated in 1,750 feet of water depth. It is a 40-90 million barrel prospect with direct hydrocarbon indications. The objective is middle Miocene and it is very similar to our Zia Fields, but considerably bigger we think. The well costs around $20 million. We have a great start on it, things are going well. Our intention is to sell down here and we have several interested parties, but the deal is not yet signed. We are happy to keep 100%. It is not our MO, but if we end up with 100% of this well, we are quite happy to have it. The other two wells that have rig operations currently are the completion at the Front Runner A4 well and the completion at West Cameron 295.
We are going to review operations in three of our core areas and I will start with Front Runner. Currently, the field is producing 43,000 barrels equivalent and the A4 well again is in completion operation, expected to be online by mid-September, and we would anticipate about a 10,000 bpd rate from that well.
There are other developments related to the Front Runner basin, however. Recently, many of you are probably aware that there is an announced discovery southwest of our approximate 100,000 acre holding in the Front Runner area at Knotty Head, which is Green Canyon 512. That discovery was jointly announced Unocal and Nexen with 300 feet of pay on a large four-way closure in the Miocene.
We have talked for some time about this middle to lower Miocene play and its potential across the Front Runner holdings, and Knotty Head now appears to confirm this potential. Our Yankee
Clipper prospect which we have talked about in the past is a direct offset to the Knotty Head discovery, and we believe a portion of that likely productive structure is on the Yankee Clipper, exists on the Yankee Clipper blocks. Now, we own those blocks at 50% and Spinnaker is the operator. So we are watching those developments pretty carefully.
Additionally, the next four way closure immediately to the northeast of Knotty Head is the Boxman prospect. That is a new name but we have talked about this prospect in the past at the time that we bid unsuccessfully on Knotty Head. Boxman is a four way closure, it is related to a salt feature and is separated from Knotty Head only by its syncline and is about a block away.
Other deep inventory in the Front Runner basin includes Quatrain Deep, Front Runner Deep, Exacta Box, and Lexington, all prospects we have talked about. So we now have six prospects in the Tahiti to Knotty Head section that are untested in and around our Front Runner holdings and we should see some exciting things come out of that campaign over the next year or so. It is likely that one of these wells will be drilled as early as the first quarter of 2006, depending on rig availability.
Turning to Independence Hub in the Eastern Gulf, all three Spinnaker discoveries to date are on track for first production in the first half of 2007. That project mechanically, by the way, is going very well. A significant expansion of the project is currently being considered by the owners, maybe to as much as 1 Bcfe of gas equivalent per day processing capacity. Currently our feeling about that is that Spinnaker would look favorably on that additional capacity as we do have additional inventory in the area.
Our Seventeen Hands prospect is on track for fourth quarter of 2005 first production, and that should produce 8 to 10 million cubic feet of gas per day net to our interest. The Thunder Hawk Basin, there is going to be quite a bit of activity coming up and this is a basin in which we are really well situated. We announced that drilling was suspended on the 734 #2 well, Thunder Hawk #2 due to loop currents. A rig will return in the fourth quarter to test the deep section there. We were unable to get down and waited some time on loop currents and decided just to bag it until we got out of the loop current season. We are excited about that deep potential, as you know.
Three development alternatives are currently being considered for Thunder Hawk. The Thunder Horse Semi-Submersible, the problems there related to Hurricane Dennis are well chronicled. But ironically, we don’t believe that BP’s misfortune in this case, should a deal be done to process the Thunder Hawk hydrocarbons, we don’t believe that these problems are necessarily a negative, and may well be a positive for our project.
It really relates to down time charges. In the project sequence that we anticipated, Thunder Horse would have been producing at a pretty high rate at the time that we needed to make modifications should those hydrocarbons come aboard. This would lessen those downtime charges, maybe even eliminate them, depending on what BP chooses to do with the semi. So actually, we don’t believe that either timing or cost are harmed by the events concerning the Thunder Horse Semi.
The other two development alternatives are third-party self-builds. There are several parties interested in financing a project potentially there, and this could be key for this really prospect-rich basin. We now have an inventory of five prospects in the basin. At least two of which are likely to see drilling in 2006 and have significant potential on the order of Thunder Hawk and in one case, maybe bigger. So a third-party build or self-build is not out of the question.
The third alternative might be the Devil’s Tower Facility to the west, owned by Dominion. Probably in any event, our first production at Thunder Hawk would be an ‘07, most probably 2008 event. But it would be significant when it occurred, we believe. Again, we continue to believe the field itself is 50-150 million barrels and the basin of course looks very promising to us. We own, by the way in those five prospects in the basin, somewhere in most of those prospects, 25% interest, but we own one-third of one significant prospect in that basin.
I want to turn to Nigeria just for a minute. The most recent development is that Shell in the past week has announced the Etan discovery. Etan immediately offsets our northern block boundary on OPL 256 and was announced as a significant discovery. Shell, at the same time, announced a follow-up well would spud in September, a delineation well. As we have it mapped, 30-40% of that Etan feature lies on OPL 256.
In addition to that development, our second well, exploratory well we now believe will spud in October and we are going to drill on a very significant size feature with direct hydrocarbon indication.
The risk on that prospect is, as we said it was before, and that is hydrocarbon mix. We believe there is a very high probability that hydrocarbons are present. It is a question of how much, is it gas or oil and what is the mix in those product types.
Again I would reiterate in Nigeria, and West Africa in general, we are building a business, and you should expect to see and hear more about additional positioning in West Africa from Spinnaker and we are working hard on a couple of things that we think will occur.
Turning to guidance for a minute, we confirmed our yearly production guidance of 50-55 Bcfe and we did that in spite of a couple of billion cubic feet of visible reductions from a shut-in at Brazos A19 and some storm-related shut-ins for the past couple of months. Brazos A19 was shut in for gas quality issues, not a reservoir issue. In fact, we and the operator are looking potentially to a second well on that block, so it has performed extremely well, over 100 Bcfe to date, and still capable of very high rates.
So, taken in context, we really believe that the cited production range is a positive and in fact it was likely that we would have lifted our production expectations had we not had the developments at Brazos A19 and these storm-related shut-ins. But we feel pretty good about the guidance that is out there. We will feel better we when get past storm season.
In conclusion, Spinnaker had a great quarter in the second quarter, one of our best ever, and we feel like we are certainly headed in the right direction. We think our exposures for the second half of 2005 are at least equal in quality to those that we have drilled in the first half. So, we are feeling pretty good, and with that, I will take any questions.
+++ Q&A
Operator: (Operator Instructions). We will take our first question from Joe Allman from RBC Capital Markets.
Joe Allman: Good morning, everybody.
Roger Jarvis: Hi, Joe.
Joe Allman: Roger, in terms of previous discoveries that don’t have all the credit for reserves, besides the ones you have mentioned already, could you give us a list of the others and what events would get you the reserves booked?
Roger Jarvis: Yes, I think there are several. In the Eastern Gulf, the Spiderman discovery is booked, I believe, to about mid-300 range. We think that field is likely mid-400. It is a hydrocarbon indicator basin prospect at multiple levels, so production is the mechanism through which we get additional bookings. Although one additional well is scheduled for the second half of this year and it would have some incremental booking attached to it, maybe as much as 40 Bcf gross.
The San Jacinto discovery as well is in that category, hydrocarbon indicator basin accumulation or expressed accumulation. And we think we are under booked there, so to speak. Performance again will be the main mechanism, although a third well should be drilled there as well into a separate full block and some incremental bookings are probable there when that well gets drilled.
The Goose project is one that we have not talked a lot about lately, but there have been developments. We think we are getting close to a deal that would see another well drilled on Goose to a very prominent amplitude in the section, and could bring a development to that project. We are not really ready to talk about all the details yet. It is not fleshed out, but the area has an additional discovery now to the north, and third parties willing and motivated to talk about building potentially a facility. We are not calling it yet, but we are getting closer to something that might constitute a project at Goose, and we are currently not booked there at all.
Front Runner has a multitude of undrilled infield amplitudes so to speak, that I think down the line, we are going to see come to the reserve category. It is a bit early to comment how all that is going to work out or how timing will work out on those additions, but you know, there are some substantial infield opportunities that don’t need any kind of reserve definition, and aren’t expressed even in our P2, P3 numbers.
So those are a few of the things, Joe. There are other odds and ends out there, but I think on whole the mechanism through which we book keeps us conservative.
Joe Allman: And then at Front Runner, does the production that we have seen so far from the four wells on line give you any hope to get some additional reserves just based on performance there?
Roger Jarvis: I think a majority of what we would see in the form of new reserve and those wells are really behind pipe or relate to sidetracks from those locations. As a practical matter, it will be sometime before we deplete those zones and go on to others that might be booked and currently aren’t booked.
Joe Allman: At San Jacinto, what is the basis for the booking you have already there?
Roger Jarvis: I think we are booked to about 130 Bcfe. We have booked a bit less than that 130 Bcf gross currently, but we think our resource estimate is 130 to 150 Bcf.
Joe Allman: Okay, and then lastly, in Nigeria, what, Shell is going to drill the second well, what is the plan with that immediate structure there?
Roger Jarvis: Well, we don’t plan drilling, but the process for approval of a project is one that gives us some comfort that will be considered before the development plan gets approved, so, I think it is likely to be that if our mapping is correct, and we feel pretty confident, if some of those hydrocarbons are on us and it is a commercial project, then I think we will be involved in it. I don’ think we have to necessarily drill an exploratory well right now to find out.
Joe Allman: Any guess of on the size of what Shell found out there? I know the Big Cats are a minimum of 100 million barrels.
Roger Jarvis: Yes. I wouldn’t speculate. We have got our ideas internally, but you know we are not in possession of all of the data so we will hold off. If it is commercial, it has to be probably well north of that number you are talking about.
Joe Allman: All right. Thank you.
Roger Jarvis: Thank you.
Operator: We will move next to Kim Pacanovsky of KeyBanc Capital.
Kim Pacanovsky: Hi, Roger.
Roger Jarvis: Hi, Kim.
Kim Pacanovsky: Congratulations on the quarter.
Roger Jarvis: Thank you.
Kim Pacanovsky: A question about Yankee Clipper and Knotty Head. You said you were planning on drill hopefully one well in the beginning of 2005 in that area. Will it be Yankee Clipper? Have you decided what the next well will be?
Roger Jarvis: The well I’m referring to is probably in the immediate Front Runner area, Kim, and it is probably either Lexington or Quatrain Deep. The plans for Yankee Clipper really have not been finalized, but again we are the operator. We own 50%, so we are starting to take a very serious look at what we might do there.
Access to early production schemes is also important. And we do have a fair piece of that facility at Front Runner so that might factor into our thinking down the line as well.
The prospect immediately to the northeast of Knotty Head, Boxman, is one that we have not yet factored into the schedule. It could be that things change and rather than Lexington or Front Runner Deep, that the partnership might shift their focus to that feature. And, I will tell you, we would be supportive of that, but we are not to that point yet.
Kim Pacanovsky: What was the potential reserves at Boxman?
Roger Jarvis: Boxman is a pretty big feature. It is a couple of thousand acres on one block and maybe 1,500 to 2,000 acres on a second block. So it could be sizable.
Kim Pacanovsky: Further reserve adds, could you break up the oil and the gas in the 91 Bs added or found, rather?
Roger Jarvis: I think a majority of it is probably gas, Kim, because “Q” is virtually 100% gas. 295 is pretty rich, but I think you can assume that most of it, a vast majority of it is gas.
Kim Pacanovsky: Okay, and as far as the escalation of the budget, could you just give us an idea of how much of it is cost escalation and how much of the increase is going to projects related to success?
Roger Jarvis: I would say it’s 75/25.
Kim Pacanovsky: 75% cost escalation?
Roger Jarvis: No, 75/25, incremental success, and by the way on the gas oil mix, Thunder Hawk is in there as well, so it is probably closer to 50/50.
Kim Pacanovsky: Okay.
Roger Jarvis: Sorry about that.
Kim Pacanovsky: Okay, all right. I think that’s all I have. Could you give us a little bit more explanation of this gas quality issue at Brazos A19?
Roger Jarvis: We really can’t. I mean Shell is working on that. It is an issue of trace elements and it has to be processed. It is not a particularly vexing mechanical problem. It is just we have to build the vessels and scrub those elements out of gas.
Kim Pacanovsky: All right. Thanks a lot, Roger.
Roger Jarvis: Thank you.
Operator: Our next participant comes from the site of Ryan Zorn of Simmons & Company. Ryan Zorn, go ahead, please?
Ryan Zorn: Sorry, guys. Are you there?
Roger Jarvis: Hi Ryan.
Ryan Zorn: I apologize.
Roger Jarvis: Okay.
Ryan Zorn: On the bookings at Thunder Hawk and “Q,” you look to be pretty flat there until you get more wells drilled, or how do you think about that? Given the proximity until June 30, did Ryder Scott have enough time to give you all that they will this year or do we look for more towards the end of year?
Roger Jarvis: Yeah, I think “Q” likely is booked to where it is going to be until we put it in on production. There is not going to be a second well drilled there. We can drain the whole - what we think is a 140 or 150 Bcf from a that single well, and it was designed that way. So the first upgrade there will come in 2007, after we have had sufficient production history to justify it.
At Thunder Hawk, I think there the drilling is going to impact us pretty considerably. We are going to see the deeper section in the #2 sidetrack well when we get back on location there, probably in the fourth quarter. Additionally, we are going to drill a Thunder Hawk #3 well and part of that well is likely to be drilled in 2005, but more probably that well be decisioned and evaluated in the first quarter of 2006. That could be a pretty significant reserve addition. It is going to test the northern flank of what we think is this accumulation. So you could see some considerable bump by virtue of those two well activities.
Ryan Zorn: Okay. On Krakatoa, that’s still early 2006 type of spud date?
Roger Jarvis: Yes.
Ryan Zorn: Okay, and you have the rig lined up?
Roger Jarvis: Yes.
Ryan Zorn: And then I wanted to just ask on your jack-up program, this is probably a more of 2006 question. Obviously we are getting more definitive word on some of the assets leaving to the Middle East, how does that impact your thinking on 2006?
Roger Jarvis: Well, I mean if you diminish the population of rigs, that has been the mechanism through which rig rates have been maintained and increased. I mean, we have the same number of rigs operating that we had 18 months ago, virtually on the Shelf, so attrition is the mechanism through which day rates are increased. So if there are additional rigs leaving, that’s a concern, but I will tell you that what we have seen in the past quarter is some resistance to additional day rate increases, and there are a few plays that probably aren’t quite as sensitive to it, but on the other hand, at least in our case, we have some flexibility about when and how we drill wells on the Shelf and as always, we are not scared to reduce our activity if we think things are overheated.
Ryan Zorn: Are you noticing any sensitivity on your part or your partner’s part on deepwater asset day rates at this point?
Roger Jarvis: Not so much there, at least in the ultra deep because there are so few rigs capable of drilling, and the prospect sizes are larger. We have not seen a lot of sensitivity there. However, you get to the kind of day rates we paid for the Cajun Express, we would choke if things go much beyond that. So.
Ryan Zorn: Okay, we will keep watching. Thank you.
Roger Jarvis: Thank you.
Operator: Our next participate is Irene Haas of Sanders Morris Harris.
Irene Haas: Hello Roger, congratulations for a really nice quarter and the reserves pattern as well. My question has to do with the Front Runner area, the deeper Miocene trend you have been about forever and you know with the recent discovery at Knotty Head, would it make sense for you guys to maybe bump it up into the front of the queue, if not anything, to know how much you absolutely own before any unitization conversation can happen or maybe some of those being drained?
Roger Jarvis: I’m not sure that it would be. The way we see it right now, Boxman really might not be a candidate for unitization. It is a separate feature. It is the very same structural trend, they are not separated much in distance, but we have access to facilities there and others don’t.
So, at this point, I think it is premature to say that there would even be common conversations, you know, in the early stages. We will see how that develops. As to whether it goes to the front of the queue, I mean, that is going to clearly be a conversation that we will have with our partners and we will sort it out amongst ourselves, but I think you could see an increased profile for Boxman.
Irene Haas: How soon if you guys decide to, you know, as to logistically possible, I mean, you know, looking at all the projects you have in front of you, to add one more?
Roger Jarvis: I think it is possible largely because we don’t operate Boxman. Murphy would be the operator if that prospect got drilled. I think logistically it is possible. It is going to be a more matter of probably rig availability and under what terms and when we might be able to apply
capital. Now, this is without knowledge of where our partners stand in priority on that prospect. So we will see, but we are pretty excited about it right now. And I think our mapping is a fairly sophisticated map of the area.
Irene Haas: So, let me get this straight. Yankee Clipper and Boxman, while they are on the same trend with Knotty Head are not connected, that’s what you are saying?
Roger Jarvis: That’s correct. The Yankee Clipper blocks are actually on the Knotty Head structure. We think that part of that field could well be on at least one of those Yankee Clipper blocks. That’s how we have it mapped. The Boxman is a completely separate structure, separate from Knotty Head, to the northeast.
Irene Haas: Thank you.
Roger Jarvis: Thank you.
Operator: We will move next to the site of Michael Scialla of A.G. Edwards.
Michael Scialla: Good morning, Roger. All my questions have been asked except for one. I was curious what price you were using to calculate your mid-year reserve PV-10 number?
Roger Jarvis: We used the $7 gas and $56 oil. It is stipulated by the SEC. Those are the prices as of that day.
Robert Snell: Mike, we use the field prices as of 6/30 at the actual, it varied from location to location, but it is actual field prices at that date.
Michael Scialla: Those are field, so those are not — that’s the well head price.
Robert Snell: Right, by SEC rule, you have to use the in-field price.
Michael Scialla: Thank you. Nice quarter.
Robert Snell: Thank you.
Operator: We will move next to the site of Phil Pace of Credit Suisse First Boston, go ahead.
Phil Pace: Morning Roger, how are you?
Roger Jarvis: Hi, Phil, how are you doing?
Phil Pace: I’m doing good.
Roger Jarvis: All right.
Phil Pace: Reporting from the dark side.
Roger Jarvis: We will be careful.
Phil Pace: A couple of questions today. Have you run a well with that PV-10 today and maybe more importantly, if you gave a cost forward or all in cost at “Q,” what do you anticipate the likely range of all-in development costs to be at Thunder Hawk? I know there are several options, but what is the likely range?
Roger Jarvis: Yes, that’s a tough one. Let me start with the first one. We would be, on an equivalent basis right now, $4-$5 above the prices that we used at mid-year and that is a flat pricing, so depending on how you view the price a year or two out might affect it some. But it will be at least 10% higher, maybe a bit more. In terms of all in development cost at Thunder Hawk, we have looked at a number of scenarios. A three-well development, you know, I think it is high $200 million range. If you go with a self-build, it depends on how much is contributed by the third party and on what basis, but it could go into the low $300 million range. So it is a fairly inexpensive development by these standards, particularly if you get to the 75 million barrel range. It is extremely commercial.
Phil Pace: So, net-net over time, that is going to be one of the factors that pushes down on your DD&A rate.
Roger Jarvis: Yes.
Phil Pace: So how many prospects do you have in that West Cameron trend and what’s the typical well productivity in terms of rate?
Roger Jarvis: Very high rate potential, certainly 30 million plus and the well is capable of doing 50 and historically, wells that have made 100 million a day in that play. The very first wells in the play that we have drilled — really, now, seven or eight years ago. The advent of new data has made the play more visible and more understandable, I think. Those wells are costing $15 million, roughly.
Some could go a bit higher deep in the section. This is a play that sands lie right on top of the Miocene marker and so it is a play that has, there is a pretty large vertical section that is potential. So wells could go from a 15,000 to 22,000 or 23,000 feet depth and be part of the same play. But all-in development costs when you are looking at prospect size of 50 to 100 Bcf in many cases, I mean, they are terrific projects.
Phil Pace: How many in your inventory?
Roger Jarvis: We will drill 10 wells, 10 exploratory projects in that play in the next 15 to 18 months. It will be a majority of our exploratory expenditure on the Shelf, and should be.
Phil Pace: Interesting. Thanks, Roger. Nice quarter.
Roger Jarvis: Okay, thanks, Phil.
Operator: Our final question is a follow-up from Mr. Joe Allman, RBC Capital Markets.
Joe Allman: Hi again, Roger. Could you remind us of your plans or update us of your plans in the lower tertiary play and also, just in general, do you expect that Spinnaker will take on more operatorship and thus control the timing and costs, et cetera going forward?
Roger Jarvis: I think that is a continuing trend, Joe. We are operating now a third to a half of what we do in the deepwater; for new projects, probably closer to half, and that has been part of the plan from day one. We are now the operator of record, I think, on 40 or 45% of the properties in which we own an interest in the deepwater. So that is continuing.
In terms of the Miocene or lower tertiary play, we have chronicled our strategy there for some time. We continue to add regional data. We add to our seismic database. We have done a lot of processing. We have done a lot of digesting of the data that is available through other’s activity.
We do have some positioning in the play, but we believe that the real opportunities are out in front now as people attempt to drill prospects in front of their lease expirations. There is an opportunity to participate, learn further, and maybe be involved in some projects. But there is also going to be a big turnover of leasehold in that play over the next two to three years, and Spinnaker is going to be very well positioned, at least from a data point of view to take advantage of that and we intend to be involved, and most of our efforts now are focusing on which particular areas do we think have the most potential in, and we think we are down the road on that assessment.
Joe Allman: Do you plan to drill any lower tertiary in 2006?
Roger Jarvis: If I were a betting man, I would think yes. I don’t believe that that will come from our existing inventory. I believe that will come from solicitation of others who are likely to drill wells in areas that we think have potential.
Joe Allman: Did you previously have one plan with Chevron Texaco? And what is the status there?
Roger Jarvis: We did. But it is not on the drill schedule for 2006 at this point. They had it on their schedule and it is no longer there.
Joe Allman: That’s just based on digesting the data?
Roger Jarvis: Yes and, frankly, it is a big prospect so it might not be the first one we drill.
Joe Allman: Alright. Thanks, everybody.
Roger Jarvis: Thank you, Joe.
Operator: There are no further questions at this time. I would like to turn the program over to Mr. Jarvis for any concluding remarks.
Roger Jarvis: Very good. We thank you all for dialing in and being part of the call.
Operator: Thank you. This does conclude our conference for today. You may now disconnect your lines and everyone have a great day.
