Ranger Oil Corp (ROCC) 2003 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen and welcome to the Penn Virginia Corporation second quarter earnings conference call. At this time, all participants are in a listen-only mode and a brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star, "0" on your telephone keypad. As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer of Penn Virginia Corporation. Thank you Mr. Dearlove, you may begin.

Thank you and good afternoon to all of you. The operator tells me that we have got a fairly full queue so let's get on with it here.

As is my want, I always forget to introduce people before I get started, so let me do that. In Denver today, we have Frank Pici and Baird Whitehead. CFO and Head of the Oil and Gas company, respectively. In Kingsport, we have Keith Horton, who is the President of the MLP, Penn Virginia Resource Partners and here in Radner, we have myself, Nancy Snyder, who is our General Counsel and Senior Vice President and Gene Whitehead who is here just to keep an eye on us and to take some notes even though this is being recorded. So, among the group, we hope to be able to answer any questions you might have and we certainly encourage you to ask them.

I typically do not read to you the press release and I don't intend to today, in fact, I'm going to bounce around a little bit between the press release of yesterday and the press release of late July, the operations reports. Clearly the numbers were very, very strong for the second quarter and first half, net income was up 100% in the quarter and 158% in the half. Operating cash flow was up over 80% by both measures. Revenues were up, et cetera. That is not necessarily a result of anything that we did, of course, except we put ourselves in a position to benefit from high gas prices and that's what's driven these results.

We're about 83% gas and a 58% increase quarter over quarter on gas prices and a little higher than that, I believe, year-over-year has surely driven our results and you'll see most other E&P companies having some pretty dramatic results for the first half of the year.

What comes around goes around, and I don't want to be negative but clearly prices are cyclical and the same things that sometimes drive them up turn around and drive them back down again. Not to say that's coming but nonetheless we acknowledge the fact that it is high prices that have had a lot to do with it but increased production has something to do with it, too, we are up about 14% in the quarter, 17% for the year. Much of this is a result, frankly, of the Kingsville acquisition, which the acquisition itself, which we made in January this year added some production immediately to the company but we've also been drilling there and we've drilled three successful wells in the quarter and we intend to drill five to seven more through the year.

So, we've been spending our money in Kingsville. That's been the bulk of our development drilling in the West throughout the first half of this year. Referring to the July 31st press release only for a moment because it does give a summary of the oil and gas operations, we drilled 84 wells, gross wells in the first half of the year, 64 net and that's up about a third from the year before. We expect to repeat that in the second half of the year drilling 80 to 90 wells in that year. We broke it out a little bit.

By the Western region, where, as I said, in the quarter we drilled five wells, three of them in Kingsville, two of them exploratory, one of them was not a success, the other one was, we'll expect to ramp up our exploration drilling a little bit in the second half of the year what we might drill three or four wells, including one to verify some ideas we have on something called Finet, which is a very important salt dome that we're drilling which we acquired as part of our Gulf Coast acquisition about a year and a half ago and the other one is to drill a Yehwah prospect, which again, was acquired about a year and a half ago and if it works, will have some considerable potential to it.

In the East, we drilled about 73 gross wells with a 99% success rate. We would expect, again, to more or less repeat that or maybe a little more in the second half of the year. Included in those wells we'll try two what are called Myacine wells, fairly shallow, 6,000 foot wells that are drilled off a tuti seismic. This is being managed in the East because it is more akin to the Eastern mindset and Eastern technology. So, that will be handled there.

Again, not reading everything that's in that press release, but I would point out that we drilled four horizontal coal methane patterns in West Virginia, two on Twin Branch and one up in Loop Creek. We're drilling some more as we speak. We hope to drill 10 to 15 additional patterns through the last of this year.

Then lastly, and then I'll get off that release but this is important. On our own ideas, ideas developed in Baird's shop, we've gone off and taken a position in the Cherokee Basin in Kansas. We're not the only one there, but this particular idea was ours. We have a 100% working interest in working as an operator on this. We've drilled five wells, all of them had coal, we have tested for gas, we'll go on testing. It may or may not work. It certainly gives every indication that it is going to work right now as the completions are finished up and they should be finished up by the third quarter this year, that 45,000 acres that we had there can be drilled on 80-acre spacings. So, if you do the arithmetic, you come out with 500 wells. I'm surely not predicting that. I'm merely telling you there's a potential there for some significant coal bed methane additions to our low-risk development inventory.

One other note on drilling so far this year, we've gone, had some success in South Louisiana. In fact, we're three for three drilling wildcat wells, one in Versard, which is in Lafayette, right in the city limits, and two, in a field called Stella where there may be some more activity. We're quite pleased with that, of course. We're disappointed and I want to acknowledge it in the fact that in also in putting out our guidance last quarter, we took at face value and perhaps shouldn't have but took at face value the estimates the operators gave us in terms of getting those wells connected up and we've run into some delays there due to, frankly, acquiring rights-of-way.

We've also had some delays that are weather-driven and we've had some delays getting the number of rigs we wanted when we wanted them for our coal bed methane projects in the East and those are frustrating and they've caused us to move down our guidance on production a little bit for the year.

But I would say that guidance is just that. It's guidance. It is an estimate and we've made every attempt to be as accurate and forthright as we could in giving our guidance. If we had it to do over again, clearly we'd have been a little more conservative.

But what I hope what you would take away, you can be critical of our estimating and that would be fine but take away this, the gas is there and the gas, whether it gets produced in the third quarter or the fourth quarter or the first quarter of '04 surely affects the net present value of things. But it's much more pleasant to report to you we've had to lower our guidance a little bit because of these delays than we've had to lower our guidance because the gas wasn't there.

As a matter of fact, and then I'll shut up about this, if you look at our drilling this year, there is much reason for optimism. To go 3 for 3 on these wildcats in South Louisiana is some indication that the fellas in Houston know how to pick the right prospects. What we've done in horizontal CBM this year is basically prove that we can do it cheaper, that we can do it in tight coals and it will work off structure. The fact that we've developed our own ideas in the Cherokee Basin and they're proving out, I think is good reason for optimism going forward.

Again, to not read the press release to you, there's a description in there of our cap ex for the quarter and just to break it down, about 60% of it's gone into development drilling, about 11% into exploratory, 9 into seismic and 20% into leases and infrastructure. So, what you might take away from that is we are indeed trying to build our own production shop. That's a lot of money to be spending on seismic and lease acquisitions. That's basically what we told you we're gonna try to do and I would contend we're having some success doing it.

On the PVR side, not to go through it in great detail but it is a very important component of the company, basically what you'd see there is that Penn Virginia Resources is right on course. Revenues are up for the quarter and they're up for the year. Production of gas by our, or excuse me, coal, pardon me, by our lessees is up as you would expect because the first quarter of last year did not have in it the contributions from the Peabody Alliance nor the Upsure assets that we acquired late in 2002. The increase in revenues is carried down to the cash flow line, which is what's important in an MLP and we're finishing well ahead of last year.

Some of the expenses are up. DD&A is up a lot and that's because the new assets we bought are clearly carrying a higher DD&A rate than assets we've owned for a hundred years and are basically fully depreciated. The G&A is up reflecting mostly the post-9/11 increases in D&O insurance, which has gone up in rate and we've gone up in the amount of insurance that we carry because that's what you need to do to have good directors these days and there's the cost in the G&A that flopped over from '02 into'03 with regards to the Peabody acquisition.

The operating expenses are up, as well and a lot of that has to do with what we used to call the Four Creek Mine, which we were spending money keeping operational, keeping it from flooding, keeping the ventilation working while we sought another lessee. We've got another lessee. Those expenses will go away in the third and fourth quarter. That lessee began to produce coal on June the 25th. He shipped his first coal on July the 30th of this year. So, we're in production. It will be an 18-month or so process to ramp up. We've only got about 230,000 tons of that production built into this forecast. Over time that will ramp up to a number maybe 10 times that.

Just very briefly, it's not in the press release that we put out for PVR yesterday but we have completed now the Peabody deal by going through the exercise of converting their class B units into normal common units. So, they are not subordinated. They weren't, anyway, but they now have common units like every other common unit holder.

Penn Virginia, of course, remains in subordination and we've done a little bit more of our fee-based asset stuff with PVR where we've begun to undertake construction of a load out in Virginia that's a high-speed load out, it will load 150 cars and should improve the salability of the coal coming off of our Four Creek assets.

So, with that, operator, I think I'm ready to take questions.

Certainly. Ladies and gentlemen, at this time we will be conducting a question and answer session. To allow everyone the opportunity to ask a question, please limit your time to one question and one follow-up.

If you would like to ask a question, please press star 1 on your telephone keypad at this time. A confirmation tone will indicate that your line is in the question queue and to remove yourself from the queue, please press star two. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Please hold one moment while we poll for questions.

Thank you, ladies and gentlemen. Our first question is coming from Joe Allman. Please pose your question.

Good afternoon, everybody.

Hi, Joe.

Jim, can you give us what you think the timetable will be for getting additional rigs in the horizontal CVM play?

Baird, can I pass that off to you?

We expected to have that rig as of now. I would expect with us talking to these guys on a continual basis that we are gonna pursue trying to get a rig sometime the end of this quarter and the fourth quarter. But it is our plan to have that third rig running before the end of the year.

Okay. And what's the possibility for a fourth rig by year-end?

I'd say it's probably less than 50/50, Joe. I think that depending on how much time it takes us to get the third, I think it would depend on the timing in the fourth. I think we have enough inventory of prospects to keep a fourth rig busy. In fact, I know we do. But it's just the timing in trying to get all these rigs running. But I'd say probably less than 50/50.

All righty. Thank you.

Joe, over time if we can't do a better job procuring these rigs, we'll go in another direction and do this using our own technology.

All righty. Thanks, Jim.

Thank you. Our next question is coming from David Conney Please pose your question.

Hi. This is a question for Baird. Baird, what do you think your overall decline rate is right now with the mix of properties that you have?

Dave, it's about -- it's about 15 -- I think the last time I checked it was 15 to 17%, as you would expect, Appalachia is less and as you would also expect, Gulf Coast is higher.

And how has that changed, would you say, over about a year or so ago?

I'd say it's -- it really has not changed. The only thing that has really affected our decline rate is we have one material well that was producing in excess of 10 million a day as of third quarter of last year.

As with any higher volume type well, especially in the Gulf Coast, those wells will deplete quicker and that well watered up. We pointed out that well also, if I'm not mistaken, made about 3, 3.5 Bcf in a year's time.

So, the payout on the investment was extremely high but that well came off production in a fairly short periods of time after it started cutting water, in fact, the well is almost off production today. So, that is the only thing that has materially affected our decline.

But overall, with things being drilled on a routine basis and a well like that coming off production, or going off production, it really has not changed,

Okay. I'll get back in the queue. Thanks.

Our next question is coming from David Snow. Please pose your question.

Yes, hi. I came on late. I wonder if you could tell us what you think your coal thickness might be in the Kansas play and how many acres you have there?

Well, we've got 45,000 acres there and I'm trying to see what the press release says about thickness. We didn't give a lot of information about the thickness. I think we've been finding multiple seams. We've looked in a couple of areas.

In one area, Baird, correct me if I say this wrong, we had about nine feet of coal in a couple of different seams. In another area we had about 27 feet of coal in three different seams. Is that about right?

Yeah, that's correct, Jim.

Okay. And how much are you now producing in your horizontal drilling in Appalachia? How many Mmcfs a day are you making there?

Per day horizontal drilling --

About 2 million a day.

Yeah, about 2 million a day. I was just looking it up here.

And do you think that will ramp up to 4 million over the next -- by the end of the year or what's the momentum curve there?

I don't know that we're that precise in our guidance. We drilled four patterns to date. We would intend to drill another 10 to 15 patterns and you maybe just heard the answer about the third rig. We have got two running.

We oftentimes don't have full control of even those two, so it's fairly hard to make an accurate prediction there. Baird, I don't know if you'd want to hazardous one.

I'd be extremely disappointed if we're not doing better than 4 million a day by the end of the year. Yeah. That would be the lower end of what we're looking to do by the end of the year.

Could be up to 10 million?

It's possible, depending on the timing of the third rig.

Okay. Thank you.

Thank you.

Thank you. Our next question is coming from Adam France. Please pose your question.

Yes. Good afternoon, guys. I was wondering perhaps Jim or maybe this is a better question for Baird, when you look at the unit cost increase versus last year, intuitively you add South Texas production, flush production, I would think that would have a lower unit cost. Could you just run me through maybe what one-time items have impacted this number this quarter?

Yeah. Adam, this is Frank Pici. Some of the things, there were some -- other than the normal operations and the things you suggest are sort of intuitive by being in South Texas --

Right.

We had some work over costs that were expensed in the second quarter and to a lesser degree in the first quarter. And those centered around some ongoing work over that we expensed in -- we had a split between South Texas and Appalachia on that. I think it was roughly --

Most of it was probably in South Texas. We had some at Gwynneville. We had a couple deeper wells in Gwynneville that had some tubing we had to get repaired. That was expensed. We had some regravel paths we had to do in Grenado which is an oil field.

In South Texas, we had to do some gravel paths on it, routine subsurface maintenance in Matthews lease, which is a West Texas oil field. I guess you would not really consider those one-time but they seemed to be higher this last quarter. We had a material work over, we did that in Rusley, in fact, the work over is still in progress. It's recompleting in another zone. So, that was a fairly significant charge.

I guess the point there, Adam, would be looking at our guidance for the rest of the year, we don't expect those to be recurring in any major way for the rest of the year.

Great. Thank you very much, guys.

Thank you.

Thank you. Our next question is coming from Eric Sell. Please pose your question.

Hi.

I am sorry, I cannot hear you.

I'm sorry about that. Can you hear me now?

Yes.

What percentage of your forward production in gas do you have hedged?

This is Frank Pici, Eric. On our current crude oil producing reserves we have about 60% of it hedged through the third quarter of '04 and then it drops down to a somewhat lower percentage when we get out to the end of '04 and just into the beginning of '05. And we do that with a combination primarily of topless collars and we have one swap that we made when we did the South Texas acquisition earlier this year, so, but it's primarily topless collars.

Okay. And then just a question on the rigs for the horizontal wells. Are those a specialty type of rig? Is that why -- I mean, is there a shortage of those, not many of those around or what? Because it would seem to me the overall utilization of rigs isn't actually that high outside of --

Well, the company who's drilling these wells for us is providing those rigs with another participant that they have set up in an equipment division. To answer your question, which field could we get the rigs, it could take a conventional rig converted to a soft drive pull-down type rig. You can lease that type of equipment.

But to answer your question, we think that we can get these rigs in a reasonable period of time. You know, they do equip the rig with some of their equipment that allows them to apply their technology but in general that is of minor importance. It's just -- primarily just getting a top head drive rig, which is the most important part and that's something we're going to try to pursue on our own if that is the case, if that needs to be.

Okay. Thank you.

Once again, as a reminder, ladies and gentlemen, we would like to let you know that you have the opportunity to ask questions. Please press star 1 on your touch-tone phone at this time to enter the queue.

Our next question is a follow-up coming from David Conney.

Yeah, hi. Another question here for Baird. On the Cherokee, Devon is a big player there. They've had to spend some capital on the gathering system. Is there a gathering system or major pipeline infrastructure right around in your acreage?

Yeah, David, we -- you know, pipelines are important to us as far as placing these prospects. You never want to go ahead and take a lesser expectation geologically because of the pipeline situation. But in our case the pipeline infrastructure in general in the Cherokee Basin, there's a lot of large, higher pressure systems that go through that part of Kansas because of the proximity of some of the larger towns.

So, there are some large major throughput lines that are convenient to both our projects.

So, in other words, hook-up time won't be long if these wells work?

That's correct. I mean, that's exactly right. Our intent is to get these things completed here in the next few months, have them on-line probably by early fourth quarter. What we'll have to do is lay some gathering and start some compression.

Compression's gonna be the most time-consuming part. But no, it's not gonna be a long period of time to get that work done.

Okay. One more question, actually for Jim. Fork Creek, what was the volumes coming out of Fork Creek before the lease was changed and do you think you can get up to kind of the same type of volumes?

I think it was on the order of a couple of million tons a year and we would expect to get back up to about two and a half.

Okay.

Would you agree? I guess we lost Keith. That's what I think. It may have been a little higher, David. We may have been a little over two and a half when it went off-line. I don't honestly recall.

We were around 110,000 tons a month was the maximum we reached prior to --

Oh, so it's less than I said. I apologize. We expected, though, Keith, correct me if I said that wrong, too, we expect it to get up to about two and a half million?

That's correct. That will take a lot of ramp up, right Keith?

That is correct. It will take a while to get to that level of production.

Okay. Great. Thank you.

Thank you.

Thank you. Our next question is coming from Mike Beal. Please pose your question.

Good afternoon.

Hi, Mike.

Just a general question. You started out early in your comments, you mentioned how this is a cyclical business. Obviously we're in a period of high commodity prices. I would assume this translates into higher cost for rigs and leases and everything else we gotta do and yet we're spending, you know, $130 million in an increasing number of areas.

I guess my question is, is there any thought to saving our balance sheet and a little bit of our ammo in cash flow for a less booming time?

Well, I think that, Mike, we're not -- certainly on the PVA side we're certainly not stretching our balance sheet right now. We've got a lot of dry powder left on the -- are we using our cash flow for capital expenditures? Yes, we are. You know, there's two sides to the coin.

There's certainly rig rates are probably higher than they were a year ago in terms of -- and other costs are higher than they were a year ago but margins are better. I mean, these high prices are driving up costs on one hand, but I think margins are better than they were when costs were a little lower. So, I'd let Baird again correct me if I'm wrong there.

So, we kind of figure we're playing when the sun shines. What we're not doing is making expensive acquisitions right now and that's not to say we wouldn't make an acquisition but we've certainly -- we will look long and hard because a seller in this price environment clearly wants to use a price deck that's more aggressive than a buyer's gonna want to use. But I don't know that we're attacking our balance sheet in any significant way. We are using our cash flow. As I say, I think we're trying to make hay when the sun shines.

Remind me, Jim, what sort of longer term price for natural gas are we assuming when we look at all the different investments we're making?

Well, we'll use varying price decks depending on which part of the world we're in. But Henry Hubb might be, if we're looking at it right now and we're gonna do something right now, we would be -- I don't know where we'd actually be in '03. We'd probably just take the forward curve for '03, '04 we might be 4 bucks, '05 we might be at $3.75, we might let it get down to $3.50 and then let it climb again at 3%, capped at 4.

That would be a typical price deck we would use unless there there was some other mitigating circumstance that would drive that higher or lower.

Okay, Jim, if I could add one thing, on our routine drilling program we use a $3.50 flat gas price. Now, if it is a strategic longer term project, as Jim said, we would use a price deck that would, you know, deescalate over time and then escalate back up and cap it as $4 or so.

But going back to your first question and Jim was right, the margin issue is still significant because prices have gone up, you know, by a factor of, you know from an average price of 3 to 3.5 up to a price that's $5.50, for instance. Cost wise, we've really not seen the costs go up a lot. Now, there has been some cost escalations but to put it in perspective, a drilling rig today as compared to last year maybe has gone up 5% to 10%. There's still a lot of deals to be made out there as far as seismic acquisition goes. A lot of the seismic companies are hungry to continue to try to turn data and they have they're very attractive.

So, it still makes a lot of sense to be spending money today.

All right. Thank you very much.

Thank you, Mike.

Thank you. Our next question is coming from John Erwich please pose your question.

Hi. Actually this is Dan Loeb from Third Point Partners. I had a question. Given the shortfall that you've indicated this year relative to your guidance, what can we expect the exit rate in production to be for 2004?

Well, I need to look that up. Hang on a second.

As we exit 2004 or as we enter?

Exit.

Oh, I'm sorry. I misunderstood your question. We haven't really tried to provide any guidance at all for 2004 at this point. There's a lot of exploratory wells that will be drilled between now and then.

For example, if this Cherokee Basin works out, we'll drill a fair number of wells there next year. If it doesn't, we'll have to find something else to do. I don't mean to be evasive and I'm not being but we simply have not forecast '04 in a meaningful way.

How about the beginning of '04, in

Frank, do you have that number?

That would be the guidance number, Dan. Based on that, it's gonna be in the 70 million a day range, the active rate.

Okay. And I guess you guys have had to incur a little bit of additional debt in the most recent quarter, a little over $5 million. Will you be looking -- and that's due to the delays. As that production comes on stream, do you plan to pay the debt down that you incurred? j

That will depend on the opportunities, obviously, that are available out there. Our sort of process or discipline that we at least try to maintain is to have a debt to cap ratio that is -- does not exceed 35, 36% and we're well below that right at the moment. So, it will depend, again not to try to be evasive at all, but it will simply depend on the opportunities that are out there.

And Dan, from a sort of cash management/debt management perspective, if we have the excess cash and we don't have commitments to use it on our drilling program, we'll certainly pay down some of the debt. Now, what can change is where we are in our drilling program at that moment. So, it's more of a sort of a working capital management question at that point.

Okay. Thank you very much.

Thank you.

Thank you. Our next question is coming from Dick Feldman. Please pose your question.

I've got a question about the wells that didn't come on due to delays. What would be your best guess as to how much production was lost on a net basis to you because of these three wells?

Bear with me here. Baird, do you have that, or I can --

Well, I can give you gross numbers, gross production rates and our approximate net revenue entries and you can calculate it. But the two Stella wells, each one of those wells will make 9 to 10 million a day and about 200 barrels of [INAUDIBLE] a day. Our net revenue interest in those two wells is about 15%.

The Broussard well, that well is going to make 15 to 20 million a day gross, anywhere from 400 barrels to 600 barrels a day of liquids and our net revenue interest in that well is about 28%.

Are there any follow-on opportunities due to these three exploratory successes?

There could be one in Broussard to the West. It's subject and contingent upon a 3D that is currently being shot and I think it has just been shot and the data is starting to come in as we speak. There is a possibility there.

And Stella, we continue to drill adjacent fault blocks, realistically you consider exploratory by definition because they are different fault blocks but knowing that we had a couple discoveries already, it makes the risk of those adjacent fault blocks go down.

In fact, we are currently drilling a third well in Stella right now that we should have TD here probably in the next week or so. And we have at least one or two more wildcats to drill in Stella, some of those we have some development opportunities if it's successful, if fact, the one we are currently drilling, if it is successful, there would be at least one offset to be drilled if it works.

Okay. I wonder if you could update us a little bit on the horizontal coal bed methane in Appalachia in terms of flow rates, reserves, what you think your finding costs are and compare that to what it would look like if you had used vertical completions?

We can take a shot at it. And I'll just tell you that this is kind of a moving target.

If you had asked us this question even, I guess, six or eight months ago, I would have given you a -- Baird, or I, and Baird can obviously do it better than I, we would have given you a somewhat different answer because the way we were drilling was the wells was a little bit different. We were drilling this pinnate pattern which for all the world, looked like the frongs in a fern and we might drill three or four frongs, if you would.

It turns out there's a cheaper and better way to do it, and it's to drive the laterals, the tendrils in this pattern out further and drill less of these arms and drill the laterals further. And a lot of that engineering change has come out of the guys in Kingsport once they've gotten their paws on this process.

So, all of that said, we would expect that these wells will be 400-acre sort of patterns instead of 800 because you're only drill one, if you will, one pattern and not four off of a set of verticals. So, it changes some of the numbers but we would expect typical finding and development costs to be a buck to a buck and a half.

We expect these wells will vary quite a bit in terms of what they'll make, but the UR on these wells might be one and a quarter to one and a half Bcf. They might decline very, very rapidly but you'll produce them out. In three years you're basically done.

In five years you probably got 90% of the gas that's in the acreage pattern. They pay out in a year. The internal rate of return done at 3.50 Henry hub is about double what you get for vertical development.

And the problem with saying that is that there's little or no proof that vertical development would work as well as these horizontal wells because you -- I said earlier, that one of the things we were able to demonstrate this year more conclusively than in the past was this will work off structure. Our experience has been drilling vertical wells and we've been doing that for quite a long time now, drilling vertical CBM wells in the same basic holes, you can't make it work off structure. So, in one way we're comparing apples and oranges. I think I covered the points but if I didn't, ask again.

You said that the internal rate of return was about double what an on-structure vertical well would look like.

Yes, sir.

Would that put it in the 25, 30% range?

I think at 3.50 Henry hub it would be it more in the 45 to 50% range. Is that right?

Yes, that's right, Jim. Jim's right, Dick. Off-structure -- we have drilled vertical wells. In fact, we drilled quite a few vertical wells in the Appalachian basin, and once you get off structure, those wells are not economic. If fact, we quit drilling off structure wells, that was a key for us until we found new areas to drill vertical wells in was looking for structure and anticline because that's where the cleats are open and where you have perm.

So, really what this has done is unlock the potential that we would not have been able to achieve by using this horizontal --

How much of your acreage do you think is prospective for this type of off-structure development?

Well, it gets to be -- you can get a little giddy with the numbers and so, I would just tell you that we have a lease hold interest and mineral fee interest in 500,000 acres in central Appalachia. We've estimated that about 200,000 of them are prospective based on our understandings of the coals and the fact we've kinds of been hanging around there for 120 years and know a little bit about the coals that are there.

Within the AMI that we have with the company in Dallas that whose technology is proprietary to, that AMI covers 16,000 square miles. I wouldn't want to guess how much of it is prospective or not, because we simply don't have the data but, generally speaking, people estimate there's 6 to 6 and a half billion tons of coal inside that AMI.

So, you can get kind of giddy with the numbers. The reason that some of our people are out in Denver, I was unable to get out there, but they were out speaking at a conference out there. They put up a slide yesterday at that conference that said "We own 500,000 acres in mineral fee. 200,000 are prospective with a 50% geologic risk." And that's maybe riskier than we believe it to be. The potential net reserves additions from our own property would be a hundred Bcf.

So, you can get giddy with these numbers and we try not to throw them around too loosely. There's a lot of opportunity there.

And is the opportunity such that are you tempted to try to lease more acreage in this area?

Well, yes. The short answer is we are doing it.

Okay. Well, good luck and thanks for the info.

Thank you.

Our next question is a follow-up question coming from Joe Allman.

Good afternoon again. Jim, you sounded fairly optimistic about the program in the Cherokee Basin. Can you give us a little color on that?

I'd rather hand that off to Baird because what I always do, Joe, is I say too much and then he yells at me. So, I'll let him talk.

Appreciate that.

You know, Joe, based on what we've seen so far, we do have two prospect areas, one of which has around 10 foot of coal. We drove five wells in that area. We took some full cores on one of those five wells in that one area. We had coal, of course.

We had indications of the surface of gas that was being evolved from the coal once it was brought to the surface. Those cores are going through a desourcing process right now in our lab to understand gas content. But we're gonna start completion operations probably next week or two in that area.

We have subsequently finished one additional well in another prospect area that is a little bit deeper and that probably makes it the riskier part but the coals were extremely thick. We had, oh, probably three or four seams. There was one that had around 20-foot of coal. It was extremely thick and continuous and that was -- that's sort of unheard of at least the way I understand it, in the Cherokee basin. But the problem is with horizontal drilling, I don't know.

We're just going to to have to get these things completed, get them in line and see how they act and react accordingly but so far, we're encouraged.

And Joe, it's really a part of a process of not spreading yourself too thin on one hand but developing, you know, a portfolio of opportunity. So, we've got -- if this works out, we'll throw a lot of resources at it. If it doesn't work out, we're doing some exploration in the Myacine, which again are fairly low cost wells. If that works out, we'll have a delightful decision to make.

While that's going on, while we've been very successful in Mississippi drilling in the [inaudible], there's a full court press going on to see if we could acquire more acreage there. We probably talked too much about horizontal CBM but we're pounding away at that. I would think that in 2004 we'll do an experiment to try to track this horizontal technique in the shales in the East. There is a lot more shale than there is coal. We perceive there's a lot more gas in the shale than there might be in the coal.

So, what we'd like to you come away with is, yeah, the Cherokee basin might be quite an interesting front tier for us. If it doesn't, we've got a lot more arrows in the quiver.

If I could just interrupt, and this is important, on these wells we're drilling in the Cherokee, we're also finding some shales that are very organically rich. You would expect gas to be associated with those shales. In fact, those shales are so black, they almost look like coals but it's a shale, of course.

We think those shares could give us some gas in addition to the -- oil associated with them. They're not gonna be big oil wells because of the depths we're talking about here, but they may make 30, 40 thousand barrels apiece, which if you could prove that they are economical, maybe have a simultaneous CBM and conventional oil program going on. There's a lot of things we have yet to learn about this, but so far we're pretty encouraged.

Thank you.

The next question is coming from Adam France. Please pose your question.

Thank you. Two questions, Jim. Could you give me your thoughts on a stock split? And then earlier you mentioned a right-of-way issue. If you could just perhaps expand on that? I didn't quite understand the issues there?

I'll do the best I can. With regard to stock split, it's something that we certainly consider from time to time. I don't know how you think about it. I think about it that you want to try to have a stock that's at least a $20 stock.

Now, we actually got under 40 today, and the last I looked before we walked in here, we were back up over 40 or so. We had a seller today and not a lot of buyers, apparently. But at any rate, you're right on the border of I guess where I'd be comfortable. But I'm one vote out of eight on the Board.

At the end of day, in my opinion, and there surely could be others, in my opinion a stock split might give you a little bit of bump in liquidity but at the end of the day I think people buy positions based on dollar value, not on the number of shares. So, I don't know that it would do that much for liquidity but it's certainly something we would and have considered.

With regard to right-of-way, there's really two areas where that's occurred. In Broussard, which is within the city limits of Lafayette, we're not the operator but we concurred with the operator who happens to be Neufield that we shouldn't be trying to acquire right-of-way until we knew we had a commercially successful well. We've got a commercially successful well. In fact, Baird said to you that it could be quite successful, in fact maybe making 15 to 20 Mmcf a day and a couple hundred barrels of [condense], so a nice well.

They, we, whatever pronoun you want to use, didn't get the right-of-way until the well was drilled, there's been some issues because you're in the city limits, you're gonna have some fractious land owners, et cetera. But progress is being made, what we thought would take three months is taking 5 months, I don't know exactly when is it gonna be done. I don't want to promise. But anyway, there's been that issue.

In the Stella wells, there's right along the Mississippi River, there was a land owner there who really had a commanding position and he knew it. He tried to extort, that would be our word, he'd probably have a different one. But at any rate, it was unreasonable and the alternative was literally to bore a hole under the river. That is being done, I believe it's underway as we speak. So, we'll have that on-line fairly soon. But these things, you know, they happen, they're part of the process that you go through. They're extraordinarily frustrating.

Again, the important thing is the gas was there and if we made a mistake at all, it was to accept what the operators were guessing as well would be the time to get some of these things done. And frankly, we were incorrect.

Thank you very much.

Once again, if you have a question for our speakers, please press star 1 on your touch-tone phone at this time. We have a follow-up question coming from David Snow.

Did I hear you right? You have five wells down in the Kansas play and a sixth one drilling and how many wells will be down and on by year end?

David, we drove five wells in one area. We drove one well in a second area. That actually was drilled after [INAUDIBLE] as far as the activity goes.

We will get these wells completed and turn them on, but we will not be drilling any additional wells before the end of the year unless these wells are so clear as far as them being commercial wells right off the bat, we would try to -- before the end of the year. But our expectation is to get them in line, see how they're gonna act and get some confidence as far as whether they're gonna be commercial or not. It's gonna take three or four months for us to get that warm and cozy feeling.

So, we will probably not start a development program, assuming we see encouragement, until next year.

Are those five wells on 80-acre spacing or how close are they?

They're actually on 160 acre spacing. One was on an 80 acre [INAUDIBLE].

And is that expected to be the spacing that you'd use for dewatering?

Ultimately we'd probably want to drill these things on an 80-acre spacing but we would start on a 160-acres.

And is there water disposal facilities available or what's your thought there?

We would have to drill some disposal wells but there are some very suitable disposal zones that are roughly 3,000 feet deep that are very inexpensive to drill and complete and to equip. In fact, we've already got our first well permitted. So, we don't think that's going to be a major obstacle.

Do you have any offset production from others that gives you any clues as to what you might expect?

Well, the only public information that I'm aware of at this time is the project that Devon has. It is a seismic [INAUDIBLE] program, probably 30 miles or so. That has been a commercial project, and as far as I know they're still actively drilling in that area.

I think those wells, initial production rates come on at 40, 50 Mcf a day and continue to grow over a year, year and a half as they grow and get up to 100 Mcf a day these wells seem to make 150 to 200 million [INAUDIBLE] reserves. It's not real sexy as far as production rates go but the economics are solid. The costs are low and that's what makes it work, especially at today's prices.

I think we've got to keep moving only the next question, please.

Thank you very much.

Our next question is coming from David Conney. Please pose your question.

Yeah, this question is for you, Jim. Acquisitions on your own gas, you know, where would you like to see them? Would you go back to Appalachia and would you use equity if the right one came around?

Well, the answer to the last two is yes. It would have to be a real good deal to use equity, of course. But -- it would have to be a real good deal. Let me just say that. We think our stock is under valued and we'd be fairly leery of using it.

Would we go back to Appalachia? Yes, for the right deal we surely would. You know, again, we're not a coal bed methane company but it surely is becoming an important niche and if we could add to that franchise in a meaningful way, we would. As I said earlier, we are doing some leasing even as I speak.

As far as where would we like them, that is -- first of all, the emphasis is not on acquisitions per se. The emphasis is on developing our own ideas, participating with others in their ideas while we're developing our own. And so, we're not, as I sit here today, David, and this is the truth, we're not out there flogging around looking for the next great acquisition. We're sort of flogging around looking for the next great idea. We would take them where we could find them. We're not going in the water, or at least I have no knowledge or no plan to go into the water, and I don't think our board would have any interest in that.

If we could find something, we like the Rockies even though there's the take away problems, we haven't done anything yet. Clearly, we've stuck our nose into Kansas, Mississippi, and we're on shore at the Gulf Coast. So, if something fit and it was a good deal, we're obligated to look at it, but we're not out seeking acquisitions particularly of any size.

Okay. Another sort of strategic. You're in a growth mode right now and you're out spending your cash flow. You know, you pay a nice dividend. Have you thought about maybe cutting back on the dividend so this way you can, you know, maintain your balance sheet a little better?

Yeah, we have and you know, again, if you go back even five or six years that would have been anathema to our Board of Directors because we were a different kind of company then. We were basically a royalty company that had an E&P business sort of confined to Appalachia and there was nothing wrong with it but it wasn't going to be the super star in rent a car.

I don't think we're the superstar in rent a car yet either but we've clearly changed our strategy. We've changed our way of doing things. You know, this Houston office, Baird Whitehead, et cetera, we're having some success with it. There's a school of thought that says E&P companies are better plowing their money back into the ground. That's the better thing to do for their shareholders than they are paying out a dividend.

On the other hand, we also have the MLP and the MLP is also in a growth mode and provides a fair amount of cash to this company and my personal view is that the dividend is something that kind of sets us apart. We say we're unique in energy, that's one of the things that makes us unique. I think there's very logical arguments that can be made on either side.

As I sit here today, I know of no plan to reduce the dividend. I can assure you that, like stock splits and stock repurchase, this sort of thing is subject for Board meetings and I can't think of a meeting where it doesn't come up.

Thank you. Great.

Thank you. Our final question is coming from Dick Feldman. Please pose your question.

Given the excellent start you've had with drilling this year, do you think your finding and development costs could be below let's say the three-year moving average?

Baird, again I'd rather let you answer that.

I think our last year three-year moving average was $1.63. Is that right?

Yeah, I'd say there's a good chance we will be below that, or right around there, put it that way.

Okay. That's great. Thank you.

Thank you. Operator, are there any other questions that you're aware of?

No, sir. Do you have any closing comments?

No, I don't. Again, I -- we've been at this now for about an hour. I really appreciate the opportunity to have this give and take. I truly do.

I think people ask good questions and they show some interest and it's, you know, what we get paid to do is answer them. So, I hope we did a good job answering them and I appreciate your interest, all of you. Thank you very much.

Thank you very much, ladies and gentlemen. That does conclude this afternoon's teleconference. You may all disconnect your lines at this time and have a wonderful evening. Thank you.