Ranger Oil Corp (ROCC) 2007 Q3 法說會逐字稿

Greetings ladies and gentlemen and welcome to the Penn Virginia Corporation third quarter financial results conference call. At this time, all participants are in a listen only mode. A brief question and answer session will follow the presentation . (OPERATOR INSTRUCTIONS) It is now my pleasure to introduce your host, Mr. Jim Dearlove, President and CEO.

Thank you Joe. Good afternoon, I'm joined here in Radnor by Baird Whitehead who runs our oil and gas company. Frank Pici, our CFO; Nancy Snyder, who is our general counsel; we have our treasurer, Steve Hartman sitting here; Jim Dean to keep me honest, and on the line in Tennessee we have Keith Horton who runs on our coal and natural resources segment of our MLP; Forrest McNair who is our controller and last but not least, in Houston we have Ron Page who runs our mid stream gas business for our MLP. So you've got - you've got the first team here for what that's worth, During the call, among the speakers we'll make some forward-looking statements.

The risks associated with forward-looking statements are outlined in the press releases and incorporated in this call by reference. The third quarter for Penn Virginia Corporation, I think came on very well and I think as explained in the press release, and I won't read that to you, but I'll kind of follow the flow of it, the key takeaways, at least as I see it, are production which was just over 11 BCF equivalent or $120 million a day which is a record and it's the eighth consecutive quarter that we set a record. It was 40% above the corresponding quarter in 2006 and it was 10% above last quarter. Year-to-date we're up 32% over the same three quarters of 2006. Most, and when I say most, I mean 95% to 98% of our growth was organic.

So that while we've had a pretty successful acquisition program in 2007, we certainly will expect we will to contribute to our growth in 2008. The progress this year has come through the drill bit. As the release points out, operating cash flow was also a record at almost $79 million versus $66.6 million in the corresponding quarter of 2006.

Net income was $17 million which was lower than the $22.9 million in the corresponding quarter in 06 and that is driven almost entirely by changes in derivatives which is why we've given you a new measure this time around called adjusted net income. It's a non-GAAP measure but it excludes the effects of the non-cash changes in the derivative's fair value. So if you looked at - computed that number you'd come out with $18.7 million for this quarter versus $14.2 for the third quarter of 2006. We hope that adds some clarity.

Digressing from the flow of the release for a minute, I think another important take away though is the performance of PVG. PVG is our Penn Virginia GP holdings LP. It is a MLP reform in December of last year. It owns, we own 82% of it. It's purpose in life is to, is to own the GP of Penn Virginia resource partners, the underlying MLP. That PVG increased it's distributions this quarter to $0.30 a unit, an annualized rate of $1.20. That's a 25% increase over how we started the year.

In fact, and to follow the release, the increase in PVA's operating income for this quarter was primarily driven by a $9 million, 50% increase in operating income from the oil and gas segment. nd that's a direct result of that increased production as well as a $12.3 million gain on a sale of certain non - excuse me, non-operated working interest properties. It was certainly not driven by prices. In fact, comparing prices the quarter of 06, third quarter 06 and third quarter 07, they were actually down gas prices by about 9%. As the release points out, I'm not going to dwell a lot on PVR, but the operating income of the natural res - natural gas mid stream segment was up 26% or $2.9 million. The coal and natural resources segment operating income was off a little bit, about 6%, or $1 million. That was basically due to changes in the mix of lessees mining our coal. You may have noticed coal production is flat comparing quarter-to-quarter. Corporate expenses were up a little bit and as detailed in the release. I would tell you that we just completed a call here an hour ago.

PVR and PVG, and you're invited to go onto the website and you can pull down those press releases or the recording I guess of that press release, that's why I'm not going to spend a lot of time on it here. Looking at the oil and gas segment, the, again the release reiterates some of the things I just said about production and prices. It points out segment revenues were up about 29% to $73 million, also points out expenses were up considerably by about 51%. I'll just tell you, we can get into it if you'd like, but much of the increase is due to the fact we increased production so much. Increased staffing that goes with trying to build a company.

We had issues on the operating side with work over expenses and some water disposal issues, those are being corrected as we speak or fixed as we speak, it wasn't just a matter of stop trucking water and start putting it down disposal wells and we need enough water to do that in order to do it. Yesterday we also released an operating release for PVOG. Again, I won't try to parrot all that to you. I think it talks again about some of these production growth issues. It also points out our capital expenditures for the quarter were $167 million, of which $73 million was for acquisitions, $90 million for drilling and $4 million for facilities.

We drilled over 60 wells. Gross about 44 net with 98% success. If I was to point out one other thing I think is pretty important in that release, and that is that our guidance, because of the drilling success we've had, our guidance range was raised to a mid point of 14 Bs or $112 million a day and Frank will talk to you about that. He'll also point out in discussing the guidance that our CapEx guidance went to a mid point in just above $490 million.

In the Cotton Valley, and again I don't want to read it all to you, but maybe the take away is production's up 77% over the third quarter of last year. We're running six rigs right now. Our 20-acre spacing program is up and going. We drilled two wells there with very good results. We will drill three to eight more of those during the course of the year.

In Mississippi, again, 20 wells drilled. Production up 29% over last year. 8% over last quarter. The interesting take away is perhaps that the horizontal drilling there is going quite well. We'll drill a couple more of those in 2007, or I think we will. Maybe not. Maybe we got, I don' t know Baird, do we have one rig running?

We will have one running.

Okay, so we'll drill a couple more this year. That could be the future of Mississippi. We'll see how that all plays out.

In the mid continent which is an area we just got into last year, production was up considerably, but that's a brand new area. But it was up 130% over the third quarter last year. 44% higher than the second quarter this year. We drilled a number of wells there. Eight, actually, 3.5, 8, I guess, yes, 3.5 in the Fayetteville Shale. Maybe I'm saying that incorrectly, my notes are a little fuzzy here But at any rate, we've been successful on the all the wells we've drilled in the mid continents so far. We drilled a horizontal well in the granite wash and are awaiting completion there. That would be an interesting program if it worked. I think it would add to the, if it does what we hoped it would do, it would add to the value of those wells.

In Appalachia we drilled five drills total. Five of them were these, 2.3 net of those five were the multi-lateral horizontal CBM wells. Production is up slightly, about 4% there. Again, the interesting takeaways might be that a horizontal devonian share well was drilled and we're waiting to see what that will tell us. We also drilled a vertical well under the Marcellus. Again, we're awaiting completion there.

The Gulf Coast, we drilled one well that was successful. Production was up quite a bit over a last year but it was down a little bit compared to the second quarter and that's simply because of the decline rates on these wells is so steep and that was perfectly within our expectations. Just for a moment then, on PVG, I referred to it a minute ago, as I said it's distributions were increased; PVGs distributable cash flow for the third quarter of 2007 was $11.7 million which is $800,000 above what it was the preceding quarter. There's no year-to-year comparisons since it's less than a year old. As I said, iIt'll pay out at an annualized rate for this quarter $1.20 which is 7% over last quarter and 25% over the beginning of the year. I think maybe of interest to this call, the cash distributions from PVG to PVA this year in the quarter was $9.6 million. It was about $9 million last quarter. PVA's value in PVG has increased since its inception, which was December of last year by about $500 million, or $14.00 per PVA share. So we're fairly pleased with how that is going.

I'm not going to, as I've said now twice, dwell on PVR. I think the most important thing in looking at an MLP if you're keeping score is to look at distributable cash flow and for PVR that was a record in this quarter just under $32 million. If you want to compare it to what it was a year ago it was $25.2. Operating income was also a record at $31.8 million. Net income was down from, from $31.3 to $16.7 and that's that derivative issue again. For clarity we put an adjusted net income line there as well. What you'd see then is subtracting out the non-cash changes and derivatives' fair value. You would have computed the adjusted net income at $24 million versus $18 million in 2006. Natural gas volumes, through put volumes were, I believe a record at $194 million a day. That's up from $180 million a year ago and $187 million in the last quarter.

Processing margins have very good driven by spreads that were at or near all time highs, coal production was flat comparing year-to-date royalties were down a little bit. As I said, that's simply a matter of mix. The mix of our various lessees. More coal was mined in the Illinois basin where royalty rates tend to be a little lower. So that completes what I was going to say.

I'm going to ask Frank Pici to talk about the hard stuff like capital resources, derivatives and guidance.

Thanks, Jim. Hi, everybody.

I guess first off, just to mention something that is in the press release, this is a carryover from last quarter, we first put this in, we put in some equity method, financial statements in the back of the press release to give you a view of how we would account for, and how the results would look for our oil and gas business as if we treated the MLP investment on the equity method instead of having to consolidate it in. We think that gives you a better view of how the oil and gas business looks as a stand alone and in factoring in the traditional earnings from the MLP. So just a reminder that that is in the release.

A couple other things, I guess on the hedging side, just to bring it to your attention, it's not, it's not evident in the release, but if you look at our, and it's consolidated between our oil and gas and mid - and our mid stream hedging that we do in the MLP, but on the oil and gas side, our price realizations as a result of our hedging program, benefited from our hedging program in the third quarter to the tune about $0.53 in MCF so the six - $6.28 price that was shown in the press release was factored in the hedging activity, on a cash basis that would be $6.81. That picked up about $5.5 million revenue for us in the third quarter through oil oil and gas hedging activity.

Offsetting that against - and what we reported in here is a net number which takes out the cash payments we made on the ML fees mid stream hedges of $4.7 million so the net of the two is what ends up showing up in the release, but I wanted to point out to you that this has - our hedging program on the oil and gas side has provided benefits for us really for the last two year, so just to make sure you are aware of that. In terms of percentage hedged for the fourth quarter, we are about 30% or so hedged on current production as we go into 08, as a percentage of current production that it drops to about 25%. So obviously, we're keeping our ear to the ground on putting new positions on it in that area.

On the other hand, on the other side of the fence, in the MLP we're also taking a look at with the strong crash (inaudible) environment we're in of doing some more hedging on the MTA the mid stream side as well into 08 and into 09. We have a two year window we can hedge for our policy. In terms of guidance, if we can flip to, in your press release, back on page 15, there's a fairly detailed guidance table. I'll just hit a few of the highlights of those changes. As Jim, I think Jim mentioned many of these already, but if you look at the oil and gas segment at the top of the page, you'll see that we've increased the production guidance here. It's really as a result of our strong showing as the operations release pointed out last night.

When you get down into the expense categories, our cash operating expenses have been increased a bit, that's a function of both, to some degree operating expenses, but also some G&A direct - G&A related expenses have gone up as a result of our filled out of staffing requirements and that sort of thing that Jim mentioned. When you get into our DD&A we expect that to be in pretty much the same range. When we look at capital expenditures, we have increased that versus prior guidance really to, both take into account our increased development program, but also the impact of the acquisitions that we have made here year-to-date. So as Jim said, we're now projecting a full year, oil and gas capital expenditures total of around, over $490 million. So you can see that in the guidance table. That, of course, reflects itself down below in the debt categories as well when you look at PVAs, average debt has gone up as well as a result of that increase in the spending program.

In the middle of the page we have our coal and natural resource segment, our natural gas mid stream segment both of which reside in PVR. We've gone through those in the earlier call an hour or so ago. But I guess a few highlights there, we did slightly reduce our -the higher end of our coal guidance as a result of some long wall delays in Appalachia. We have gone ahead and increased our other revenues guidance there for timber acquisition made in that segment and some oil and gas royalties that were, for all effect, dropped down from Penn Virginia Oil and Gas. We've tweaked, I guess I would say some of our operating expenses and DD&A to take into account those same factors and on the capital expenditures side, we factored in the timber, oil and gas royalty acquisitions at PVR natural resources. On the mid stream side, a couple of minor adjustments, we've lowered the higher end of the guidance range just a bit. The only other thing would be slight movements in capital expenditures. And we've made a slight adjustment to the debt levels again on PVRs as a result of the acquisition activity that is now built into these guidance numbers. So that's the guidance side.

Jim asked me to, he mentioned liquidity, I guess from that standpoint, our cash liquidity is fine to get us through 07 and as we go into 08, we're just in our budget formulation time period right now and based on what, what kind of plans we formulate there, we'll of course formulate an appropriate capital, capital funding plan and we have plenty of options available in that area as well. So Jim, back to you.

Okay, thank you. Joe, I think we'll take questions

Thank you. Ladies and gentlemen we will now be conducting the question-and-answer session. (OPERATOR INSTRUCTIONS) Our first question is from Richard Tullis with Capital One Southcoast. Please state your question.

Hey, good afternoon. Congratulations on a very nice quarter.

Thank you.

My first question, I guess is on the 20-acre down space in Cotton Valley. Jim, if you could give more detail on that, such as how long the wells have been online, things like that.

I'd be happy to but I'll defer that to Baird.

Richard, the first out of the two has been online here now for about three weeks. The second has been online for about two weeks and we just actually recently finished up a third well, here to continue the fourth quarter. Just got it, drilled and completed and again it's acting as good as you would expect based on how the offsets perform, so. On one of the three wells we actually went through an extensive pressure build up analysis to make sure we had reservoir pressures that were consistent with original reservoir pressures. On one well that we did this on, we saw pressures that were virgin pressures actually, so, at least at this point in time, it does not appear we have interference. One thing we did see after running open whole logs on these 20-acre wells, is we are actually picking up some stratigraphic members that are not continuous between wells so, you're actually seeing new reserves in each one of these wells you drill because of the complex stratigraphy. So that's good news.

Excellent. Are those all on 100% acreage Baird?

Let me see. No. One was on 50% acreage with GMX and two up in the 70% acreage. We have not done any in the 100% acreage yet.

In going to your 100% acreages, how are those wells performing, the four that you drilled in 3Q?

We're still trying to get our arms around this 100% acreage. We're going to find some sweet spots, it's going to make sense for us to get into a continuous development program including 20-acre down spacing, just like we're doing down in the phase one and phase two areas of GMX. We're going to find some areas that don't make any sense to continue drilling at all because of water issues, some of these wells are moving quite a bit of water and insufficient gas and there will be some parts of that acreage that will be condemned because of that. We still feel, based on the wells we have drilled to date which is around 20, if memory serves me correct that we're already into a development program in some of those areas based on performance. So, as far as what percent of acreage we feel is prospective, we are still probably in the 50% range, 60% range. We still think at the end of the day is going to work out just fine. The remaining 40% or so will probably, we'll just discontinue any drilling at all.

Okay, excellent. Fayetteville Shale, I think you've had like two to three net wells there. Give us a little detail, if you can on that. What's it producing?

Well, our net production is fairly low, just because our interest that we have, which were primary outside operated are low, I think our net production is only about 600 MCF a day.

Okay.

We're still on a learning curve, and we still have to get our arms around our acreage position and the prospectivity of that acreage. Admittedly, what we've seen today, it has not met our expectations. We have one outside operator well, we participated in that with Southwestern, really is an average type well. The other wells we have drilled have been below average, but you know, we're getting in, this last well we drilled had a 3,400 foot lateral like some of the other bigger guys are trying to drill longer laterals. We will do six to seven completions along that lateral, so. We're trying to understand what we have at that at this point in time before we say if it's going to work or not work.

Okay and my last question, what production are you doing right now, currently? For the total company?

About $125 million a day net.

How much of that is in Cotton Valley, Baird?

Plus or minus 30 .

All right, that's it for me. Thanks so much, I appreciate it.

Thank you

The next question is from Chad Potter with RBC Capital Markets. Please go ahead.

Good afternoon.

Hi.

I guess sticking with the Texas theme at first, could you talk a little bit about the rig situation. I believe you had six rigs there. What are your plans as far as moving them around with the most recent acquisition? Where are they currently?

We have four rigs within the GMXAMI. We have one rig on what we consider the 100% acreage. We have one are rig working the mid year acquisition referred to Impresa. The crossover acquisition, the most recent one we made, we will probably take a rig down there before the end of the year. We have some locations that will be ready to go here fairly soon. We'll probably jump down there soon. We plan on keeping the six rigs working.

So you'd just be shifting a rig, not adding a new one?

That's correct for the time being, yes.

Okay. Sticking with east Texas, could you talk a little bit about the thoughts on deferring the Bossier and Cotton Valley horizontal?

On the Bossier, we just weren't ready. We are going to move that Bossier location probably to a 100% acreage location. Probably make more sense for us to do that right now. The Cotton Valley, we have not given up on it. Thinking is, the 20-acre spacing, because we're going in there and offsetting the best wells in the sweet spots. That program is going so well, and we can get a number of these wells drilled in a short period of time, it's only taking nine to ten days to, from spud to TD on these things that we think our effort is much better spent drilling those 20-acre dime space wells versus horizontal. Having said that, we will get a horizontal Cotton Valley well drilled next year. There's also been some uncertainties as far as well to drill that within the Cotton Valley. The Cotton Valley in general was fairly thick in a number of different zones within. It's not a slam dunk as far as what member you try to drill that stuff in horizontally, but I think we're fairly close to picking the lower Taylor as a member to do this in, but we will probably do that beginning next year.

Okay, thank you. I guess my last question, I'll stick in the same general vicinity, any new or near term drilling opportunities in the Gulf Coast, the (inaudible) wells kind of in decline now. What do you see going forward?

We have one well left to drill there, it's on a shallower zone. There's also a possibility of another (inaudible) at 14, which is the primary pay in (inaudible). It's going to take some more signs to figure out if we really want to drill that. But in general, we're going to have a fairly active program going forward in the south Louisiana area. We'll continue to drill wells in Stella which is a few we've drilled over the last two or three years. Creole, the same thing. Mystic Bayou, so we - we plan on maintaining a fairly active, south Louisiana, especially exploratory program going forward.

Great, thank you.

You're welcome

The next question is from Ray Deacon with BMO Capital Markets. Please state your question.

Yes, hey, Baird just the, sort of the same question on Appalachia. It sounded like you were fairly encouraged last quarter about what you've seen so far, what are your plans for 2008 do you - do you think?

Well of course we're going to maintain exactly the horizontal CDM program as we can, Ray, that to some extent is tempered by how many drilling permits we are going to come up with, but our plan is to try to keep three of these rigs busy if not more, if we can break the log jam on drilling permits. We're going to keep going forward on a horizontal shale program. We're getting these wells drilled the last quarter of this year, going into next year we'll try to understand what we have, we'll probably try to drill some more exploratory wells next year and devonian shale. And you'll probably see us start doing some things in the Marcellus, in other areas, which is the name of course that everybody is talking about at this point in time. So we're going to maintain an active program in Appalachia. It's an important area to us.

Okay, got it. Why is Marcellus of more interest do you think? Is it because it's over pressured? And you can drill them on vertical wells, is that primarily it?

Well, I think that's part of it. Plus not all Marcellus is created equal. There's a big disparity, would it maybe be able to do from the northern part of the basin to the southern part of the basin. Having said that, it does appear Marcellus is the hottest shale within a devonian shale sequence. The total organic content is actually higher in it than what you see in (inaudible) or the lower Huron. So gas content-wise, gas content is significantly higher in the Marcellus than in the other parts of the shale.

Got it,, great. And just, I guess, was this the royalty dropped down you made into the MLP. Is that, is, do you see further opportunities to do that or just kind of a one-off thing?

Well this one Ray, was certainly a one-off thing. We had sold the working interest associated with those reserves earlier this year, so we had no interest there at all as, as operators or with a working interest. These reserves are connected to coal that's already owned by PVR. So it kind of made sense to have it all under the same tent. We, as you know, we have other royalties, oil and gas royalties that we own at PVOG and at some point it may make sense to drop them down. But as we sit here today there's no concrete plan to do that.

Got it. Great, thanks a lot.

Yep.

The next question is from Irene Haas of Canaccord Adams. Please state your question

Yes, hi guys. Do you have any feelings for what your upstream production growth will be for 08? Is it going to be of the same sort of dimension at 07?

Well, Irene, in all fairness, we have not had, we do not have an approved budget and we surely expect to see growth next year. We have got a big inventory of things to do and can drill them up. We don't need to make acquisitions or do anything like that to keep running. It's a matter of how much capital we want to commit to the program. Quite frankly, that's a board issue and we're in the middle of formulating our budget and we'll get that out in early December.

Thank you.

The next question is from [Sven Geltazo] at CK Cooper and Company. Please state your question.

Good afternoon, gentlemen. Hey, how you doing? The rigs in the Cotton Valley, the six running is there a net number there --

Well, I'm not sure what you mean. We have --

Do you share any rigs with anybody?

Sorry Sven?

Do you share any rigs with another operator?

No, those six rigs are Penn Virginia operated.

Now some of them operate on areas where we don't have 100% working interest --

We did share a rig at one time maybe that's where you're --

It was a while back though.

Yes, that was a while back and that arrangement has expired.

Okay and regarding your latest acquisition and the, I'm just wondering what are the main variables that will allow the unproven reserves to be transferred into the proven category? I'm assuming drilling for sure if there's more detail that you can give me to express your confidence with regard to the transfer of probable and possibles to the proven category.

It's just a matter of timing, Sven. I mean, yes, it is dependant upon the pacing in which we drill that stuff up because of where it is, because it's due west of our phase two stuff which is really the best stuff we have so far in the Cotton Valley and because of the existing wells on the leases associated with that acquisition, we're as optimistic about that as phase two because of where it is.

Okay, so comparing the locations in this latest acquisition to what you presented in your, one of your latest presentations where they showed about a 1.1 BCF per well for a 2006 average, but with kind of a wide range for reserves per well. I mean, when you think that, when you say that you think this stuff is adjacent to your better acreage, can you give me some order of magnitude or what expectations you have for this acreage as opposed to what was exhibited in your latest investor presentation?

Well, the phase two stuff, I'll refer to as, it's still a work in progress as far as what a tight curve looks like, but we used 1.1 as an average, but it appears that the stuff done in phase 2 and it appears the stuff that we just acquired from crossover is north of that. At this point in time I prefer to give you a range, but it's probably going to 1.4 to 1.8 BCF in this stuff based on performance. We're getting gas lift installed, which is an artificial lift to move water. As the wells continue to move water and unload water, decline rates tend to stabilize fairly quickly on this stuff. So we're pretty encouraged on what we have in that part of our Cotton Valley plate.

Will you have to spend more in drilling in completion costs per well in order to get that higher reserve number?

Not at all. No. It's just better quality reservoir.

Okay, all right, well thank you very much.

You're welcome.

The next question is from Manuj Nikhanj from Ross Smith Energy Group. Please state your question.

Hey guys, just a quick question with respect to the recent acquisition in the Cotton Valley. Is that acreage - I know you said it was to the west of the 50/50 acreage, is that - is that hurdling the Pinola Harrison county line? Or is that, what region is that in exactly?

Yes, it's straddling the canyon line there, more so in Harrison County, but it's just in that neck of the woods.

Okay, and on the PUDs associated with that acquisition, what sort of EURs were given to the PUDs?

I think we used about 1.4.

1.4, okay, and then just turning to Appalachia, the lower Huron well, was that drilled on the CDXAMI acreage?

It was not. It was drilled on a joint project we have with a private company out of Pittsburgh. It's about a 13,000 acre AMI we have with those guys.

Where is that, in West Virginia?

Yes, it's in West Virginia -- It's in Boone County, West Virginia.

And the Marcellus is present on that acreage as well and below?

Yes, really these two wells we drilled are both in Boone County and they are fairly close to one another.

How deep is the Huron versus the Marcellus in that area?

The lower Huron is about, the one we drilled the horizontal well on, is about 3,700 feet. The Marcellus is around 4,300, 4,400 feet deep.

Okay and how are you completing the Huron, just uh, obviously--

We, we ran Fracers Plus, we will do a last stage frac job. We have about 2,700 foot in length on lateral. But it will be a multiple stage to completion utilizing the Fracers Plus system.

So you guys haven't completed that yet?

No, we'll be starting it here any day.

And are you guys acquiring any additional acreage, like up in Pennsylvania or anything like that from the Marcellus?

We're looking at it right now, but it's too early to say.

Okay. That's great, thanks a lot.

Thank you.

(OPERATOR INSTRUCTIONS). The next question is from Bradley [Teets] with ADT Investments. Please state your question.

Good afternoon, thank you for taking my question. It's a two-part question dealing with the 20-acre test in Cotton Valley assuming you don't anticipate 100% increase in proven reserves when it is deemed proven. Do you have a goal of either an absolute B-type number or a percentage for proven reserves if you get the 20-acre and would you hope to get that for year end 2007 or year end 2008?

Brad, , as far as a percent, what's important on these wells is making sure you have a high enough initial rate to justify the drilling of the well. So the only time information or production characteristics is, is what is most important, if you have interference with off setting wells down the road, it has less of an implication on the economics of drilling the well versus the early time information. So to answer your question, it's not, it's not black and white. I mean, if I had to make a swag, it probably would be the 75% range I think is probably a good estimate at the end of the day, but that may be ten years down the road before I can tell you one way or the other.

Okay.

There's a tremendous amount of gas locked up in the Cotton Valley, it's a huge resource because of the sheer amount of thickness and sheer amount of sand. So if you do metrics on this stuff it's a big number. But I don't think that's going to be a problem, whether it's 75 or 80 or 70. Based on the early timing of the information it's going to be the most important. I think based on what we have seen in trying to drill those 20 acre wells sooner than later, for a present value standpoint, ongoing it's going to make the most sense for us. To answer your second question, we'll be adding 20-acre PUDs over time. Some part with happen this year, some part will happen in 2008. But some part will happen in 09 and 10. We're focusing on primarily the sweet spots at this point in time for apparent reasons, but we expect to move away from that over time and keep looking 20, 20-acre footage as time goes on.

Thank you very much.

Thank you.

The next question is a follow-up Manuj Nikhanj with Ross Smith Energy Group. Please state you question.

Yes, sorry guys, just one quick follow-up. On the 50/50 acreage, I know the earlier drilling was concentrated on the west end of the acreage position; as you're moving east, are the results holding up to the, to those that were on the west end or are they deteriorating or have you guys not drilled enough wells?

We probably haven't drilled enough wells out there yet. I mean, a couple we have drilled have deteriorated slightly, but I can't give you a yay or nay at this point in time. You know, as you know, the better quality of wells down in that area, even if they deteriorate slightly they're still okay.

Yes.

So , but at this point in time, I can't say for sure.

Okay, so, so the 20-acre wells were just adjacent to those wells on the west side?

That's correct. That's correct. And we're still trying to pick up acreage as we go to the east. We're still active on the leasing, acquisition front within both those areas. So at this point in time we think it makes a lot of sense continue to drilling, not only in the 20-acre spacing but going east on the new acreage acquisitions.

And you guys are obviously looking in between, you guys are looking for more, are most of the is most of this acreage held by smaller operators, privates and stuff like that?

Yes, a lot of it is and a lot of it is trying to making deals with those kind of folks to get access to the Cotton Valley.

Okay, okay.

But there are deals to be made doing that kind of stuff Great, thanks a lot guys. You're welcome.

The next question is from Ray Deacon with BMO Capital Markets.

Hey, Frank, just was curious, given, given the level of the 2008 strip for gas, what, what would you say about hedging it at this point and I don't know, just any commentary. I'm curious why PVG is up and PVA is down. I guess, any thoughts there?

I can't really give you any insight as to why PVG would be up and PVA would be down, but on the hedging side, we find the strips looking pretty attractive right now and we there maybe come at a time to layer on more positions, Ray. I think, given that we're only 25% or 30% hedged on current production. It would probably be prudent to, in accordance with how we normally hedged to lay some more positions out there for 08 and into partially 09 as well.

Right. Your, I think I've heard you say in the past your, the most marginal stuff you had, even when rig rates were higher would probably require about a $6.50, $6.75 gas price, does that sound about right?

Probably $5.50 to $6.00 rate, depending on what plate site you're talking about.

Got it. What would you say would be the most likely area to hedge, would it be east Texas or, given the results recently would it be somewhere else?

That would be -- that'd probably be the one you'd be protecting most. We haven't really been -- we haven't really constructed our hedging program with a specific play in mind at this point, but of course that does provide benefit across our place. I guess you would say that if we're going to designate, we'd probably consider designating it most to that area.

Got it, thanks a lot.

I'm showing no further questions in queue. I'll turn the call back to management for closing remarks.

Thank you very much those of you who were on this call. We appreciate your interest and your good questions and we'll talk to you next quarter.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.