Ranger Oil Corp (ROCC) 2004 Q3 法說會逐字稿

Welcome to the Penn Virginia Corp. third 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. (OPERATOR INSTRUCTIONS)

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer.

Thank you, Megan, and good afternoon to all of you. I am joined here today in Philadelphia by (indiscernible) who is the president of our oil and gas subsidiary, by Frank Pici, who is the CFO of the Corporation and of the MLP, and Kingsport by Keith Horton, is the president of the MLP, and in Houston by Dana Wright, who is the corporate controller. I think I've got everybody.

So welcome to our third quarter call. As I try to do in these calls, I won't read to you too much. I will presume the press releases are in English and can be understood but if there's something that is not understood please feel free to ask me. And we'll do our best to answer you.

As you can see by the table that is on the first page of the release for PVA, we had a very good quarter from a financial perspective compared to the quarter last year and year-to-date compared to the year last year revenues up over 20 percent and income up 20 percent or 30 percent for the year. All the cash numbers are up. So it's been a very good quarter and that's been driven primarily by prices, particularly on the gas side and oil and gas side where prices have been up for us. I think gas prices for the quarter are up about 9 percent. Excuse me about 18 percent and for the year about 10 percent.

It has also been driven to a degree by performance of the MLP. Whole tonnage from RLSEs (ph) and we'll get into a brief discussion of PBR (ph) that is up about 30 percent for the quarter and 20 percent for the year. Coal prices are up as well, our realizations are up, considerably, about 20 percent.

So royalty income, royalty revenues are up for the quarter about 50 percent and for the year so far about 47 percent. So those things have contributed mightily to the financial numbers that you see.

If there's a negative note, it is the production hasn't been all we wanted to be and, in fact, for the third quarter on oil that we produce isn't very high; but it fell enough that it actually dragged our overall production down for the quarter slightly, the year we are slightly up.

What I might do is refer heavily to the press release that we put out on October 27th of this year and deal with the oil and gas company which took you through operations in some detail. And, again, I won't read it to you. I will try to hit the highlights the best I can.

In the Gulf Coast in the third quarter, we drilled 13 gross wells about 6 1/2 net. Five of those gross wells were exploratory about 1.8 of those net. Of those five wells we had three dry holes and that's very unusual for us. We'd gotten a little bit spoiled.

Last year for example, we didn't drill a single dry hole in South Louisiana. This year, we have. These things happen and they sometimes come in bunches. It's not all bad news, by any means. On the development side, we, of course, did quite well.

Let me just go back to exploration for just a minute and, again, parroting some of the things that were in that operational report; but we drilled a very successful well, participated in a very successful well in St. Mary's parish in Louisiana. It's about an 18,000 foot well. At the time the press release was written, it was still on test. It was making about 6.6 million cubic feet a day of gas, about 408 barrels of condensate a day.

So it looks as though -- Baird told me this morning -- that the guesstimates or estimates of the amount of reserves connected to this well is between 15 and 25 Bs, so it is a very good well and we have a 25 percent working interest in it.

It's in a region that we call Bayou Sally. Bayou Sally is a region with the exception of this well. Right now we have 100 percent working interest although we intend to sell that down. We think there is at least a dozen good prospects in that area. This particular well didn't prove up per se any of them by making them into a pud (ph) or something like that but surely raised our confidence level on the whole operations.

So that, we think, is quite good news.

Staying in the Gulf Coast for just one more minute, the other thing of note there is our joint venture with GMX Resources which is in the Cotton Valley area of East Texas. It is the North Carthage field, is what we call it. And it is going very well. We drilled six gross wells there in the third quarter, 4.4 net. All were successful. I think all four of them were successful in two pay zones (ph) and they were all successful in the Cotton Valley and I think there were all successful in the Travis Peak.

Three are in production; three are waiting to hook up or as of the 27th of October, that was true.

We would hope to drill 17 to 19 wells there total this year. It looks like we're well on track to do that. We have been running two rigs for part of the year. One of those rigs we're going to lose on December 1st. Our hope is in 2005 to get that rig back or another rig back and run two rigs there for most of the year, if not all of the year. And we are negotiating discussing with GMX exactly how we might do that.

So that's very much on track.

In the East, again just quoting out of the operations report, we drilled 28 wells in the East, total; 26 were successful, four are being evaluated, three of those were exploratory wells at one point or another that I will touch on. Despite the success in drilling, third quarter production in the East was down about 7 percent compared to last year as a total; and I will talk about that in a second what I talk about Appalachia.

The other significant area in the East is Mississippi where our activities to date have been confined to the Selma Chalk (ph) -- in the the last I guess since the year 2000 and a number of different fields. There are now three of them. We drilled almost 200 wells with a success rate of about 98 percent.

This year we drilled 8 1/3 quarter, 38 for the year; all were successful. Mississippi production is up about 29 percent in the quarter over last year because of that amount of drilling. We say and think that at these prices we have close to 400 additional wells that we could drill in Gwenville (ph) and we're going to have a fairly aggressive program or at least we're planning to in 2005.

In Appalachia, the key to Appalachia is really our horizontal CBM programs that we are involved in. We drilled nine of those wells in the third quarter (technical difficulty) participated in them. All were successful. But in Appalachia is where we've gotten banged around a little bit on the production side. As we've been telling you right along.

We were curtailed on both the Dominion and Nisource (ph) pipeline in that part of the world starting in May. Nisource up until Nov. 1st which was Monday of this week. Dominion was we were also shut in there -- I believe that was until Monday of this week as well. Is that --?

(inaudible)

Okay, I'm sorry, we turned in Dominion a little earlier than I said. At any rate, we are online now. There is no gas. None of our gas is being curtailed as of Monday of this week. So we are now flowing gas and we've tried to address some of the problems that we had to face there, the main one being that there simply isn't on a year-round basis going to be interruptable transportation available particularly on the old Columbia system.

So we bought some farm in various tranches and I won't try to run through all the details but we bought 15 million a day starting November 1st and running for ten years. We've got some other tranches as we sit here right now. I think we got 20 million a day affirm at least through this winter. Out in a couple of years and then that 15 is part of that.

And I will let Baird fill that in if I said it wrong. I think the important thing is one thing we did was we was we bought the firm. It costs money but in this gas market, it is good insurance.

The other thing we did and it had to do with driving up some of our CapEx estimates for the year. We accelerated and have now completed construction of a 12 15 mile 12 inch line. It will be in simple layman's language, a switch.

It will allow us a lot more flexibility in moving to either the Dominion or the Columbia system. So we hope that those combinations will keep us from having this curtailment issue face us next year.

I think, just, well talking about horizontal development here for a minute. We have been trying to find ways to accelerate our program in the AMI that we have with a company called CDX. Those negotiations have been difficult, but I think both parties have the best of motives. It is just we have had a difficult time of putting that together. We are not expecting any significant ramp up next year. We would expect that we will run three rigs all year.

We are talking to CDX about maybe increasing that number but no promises.

So what we have done is began a program this year drilling outside the MI (ph) with the different type technology but still a horizontal approach. We drilled one well that appears to be successful. We are going to drill some offsets to that next year. We have captured some other leases and expect to do some other horizontal CBM work northern Appalachia next year.

Also drilled a horizontal shale well this year, which we're still evaluating and we are pleased enough with what we've seen to think that we want to try it again. I wouldn't call the well a success or failure yet but we are still evaluating it. We surely have some things to learn but we are not unhappy with it and we think that the shale is an important element of what we're trying to get.

Maybe before I go to coal, Frank, there's a couple of changes in the guidance table; and since we are fresh on oil and gas maybe I'll let you just touch on those.

Yes sure. Thanks Jim. With respect to the production guidance in the October 27th release, we did mention that we would be revising full year guidance. And the current range as you can see there now is a 24.5 25.2 Bcf equivalent of gas. The only other adjustments, we adjusted our capital expenditure guidance, which I think is also mentioned in the two releases and our previous guides, I think, that we were at 115 to 120 million for the full year. We are now at $125 to $130 million which is really from a combination of things, including our increased development spending and some additional pipeline cost for constructing that line in Appalachia.

The other thing I guess I'd bring to mind here is under our corporate and other section of our guidance table back in the press release.

We had an error in what went out today -- went out last night. The fourth quarter guide shown in that release for general and administrative expenses is $9.1 to $10.7 million and just to rest assured we did not buy a corporate jet or anything that was an error in the press release. That number should have been $1.8 to $2.2 million. Giving a full year guidance number for general and administrative expenses of 8.1 to 8.5 million. So we wanted to let those of you who saw that rest easy, that Penn Virginia didn't do anything extravagant as those of you who know us know we wouldn't do that.

And we will put out a very short correcting press release just to give you the correct guidance table so we will do that here when this call is over. But, Jim, that's primarily what I was going to review (technical difficulty) guidance.

Okay thanks Frank. And Baird will -- I think when we get into the Q&A, we can elaborate on some of this stuff with regards to oil and gas and just see where people want to take the conversation.

So let me turned to PVR for just a minute; some of you I know were on the PVR call that started at 1:00 so if you'll bear with me. I don't mean to be redundant but not everybody was.

Penn Virginia Resources had a very good quarter, is having a very good year. I alluded to it a little earlier. Production from our lessees is up again for the quarter almost 30 percent, for the year almost 20. Our realization rates are up meaning the amount of money we get per ton in royalties on the average is up about 18, 19 percent for the quarter and the year. So that's driven our royalty revenues up by almost 50 percent for the year and 50 percent for the quarter.

Total revenues up 52 percent in the quarter, 43 percent in the year. I think a key to understanding the MLP is how much cash is being generated that can be distributed to the unit holders? That number for the quarter was $12.8 million, which is a 44 percent increase over '03 and through the first three months is just over 39 million and almost a 40 percent increase.

Very quickly, we raised our distribution in July to 54 cents per quarter of 216 per year. We are generating quite a lot of cash right now and it's a part of an ongoing review process, every board meeting, to decide whether to bump those distributions up again. We realize that MLPs are designed to do just that and are looking forward to being able to do it.

I think the other thing I'd point out is that we have been telling you for some time that we are and we've been showing it by our actions that we're interested in having some coal infrastructure be part of the MLP. In July, we announced a 50-50 joint venture with Massey Energy, that is basically in the business of building and developing or owning and operating, as the case may be, coal handling facilities generally at the end user point, in other words, where the coal is received. It might be at a power plant; it might be a paper plant; it might be a chemical plant but the notion is, none of those facilities are necessarily in the business of handling coal and the business of burning it.

So we are trying to put ourselves into the business of handling it.

So as I say, we've done this joint venture with Massey which we've talked about in the past. When you look at the statement seller for PVR where that Massey transaction is accounted for is in a line called "equity earnings". Not in the line called "coal services". Now I say that just for clarity.

The coal services line which is up a little bit for the year is the infrastructure projects that Penn Virginia has invested in or built on its own property, prior to the Massey agreement.

Not to dwell on too much on the coal side of things. I think, however, just for the sake of -- a little bit forward-looking. We are pretty confident that the coal markets that we are experiencing today which is in Central Appalachia, is in the low 60s for spot prices, contract prices between $45 and $55 a ton.

We think those kinds of numbers are going to stay with us in 2005, driven by both supply and demand. Recent statements by major coal producers in the East and by large utilities like AEB (ph) has said that stockpiles are down and that we should expect they will get lower.

Now of course we could have the economy collapse, we could have a very warm winter. We're always subject to those vagaries; but it looks like -- excuse me -- demand should be, for coal, should be quite strong.

On the supply-side, some of the major companies like Peabody, like Arch are publicly saying they are diverting their steam coal, coal used to turn on the lights -- coal used to make electricity, I mean -- to meth (ph) coal which is coal used to make steel, a different market.

The reason is, you're gettin the higher prices for meth coal then you are for steam. $60 is a high price for coal but Japanese steelmakers are now preparing to pay $110 a ton without transportation in it to get meth coal for their meals. They haven't been in our markets in a big way for quite a while. It's quite a change. Despite that, to generate a megawatt of electricity, it is still three times more expensive to use gas or oil.

So we think that, based on those kinds of things, that the coal market should stay pretty strong in the next year or two.

That has made it difficult for us to do accretive acquisitions. We haven't done one this year. The Massey thing will be accretive but I'm really talking about coal reserves. But it doesn't mean we haven't been looking; and as we have been saying right along another thing we've been looking at is Midstream oil and gas because we think we have some expertise there.

Two other things, just informationally.

One. This is of some interest to Penn Virginia shareholders I thing. at the next distribution paid out by PVR, 25 percent of the units Penn Virginia Corp. owns will come out of subordination and will be treated like any other common unit, which merely means that common units get paid 100 percent of distributions before subordinated units get paid anything. We haven't missed a payment for any unit and we don't intend to; but it's a bit of a risk mitigation thing for the PVA shareholder.

Another factor that affects MLPs is that section 331 of the jobs -- excuse me, American Jobs Creation Act of 2004, which President Bush signed into law in mid or late October. I forget the precise date. At any rate, the import of that is that it allows MLPs to be owned by mutual funds.

It's not a panacea. There will be some gearing up by the -- excuse me by the mutual funds. In order to own these things they are going to deal with K1 problems. They're going to have to figure how they fit in their portfolio. Etc.

So I don't expect there to be a rush (indiscernible) mutual funds to own these things. But it surely opens a broad new market for the MLPs, over time.

So we think that is a very good thing for the MLP. And that is probably enough on that subject. Except to tell you that we have changed our guidance, with regards to coal as well, we adjusted it up.

Coal royalty tons now in our latest guidance table are 31 to 32 million tons, as opposed to 29 to 30; coal royalty income is now estimated to be between $69 and $71 million, up from 64 to 66. There are other small changes like DD&A that flow through there because more tons are being mined.

But those are the two major changes.

So with that, Megan, I would be happy to take questions.

(OPERATOR INSTRUCTIONS)

Ray Beacon of Harris Nesbitt.

I have a question about fourth quarter production or maybe it's a question for Baird. Looks like the guidance is up somewhere between 9 and 10 million equivalent per day, sequentially. Is that all due to the firm transportation kicking in, or do you have any other projects coming online? And is there anything else that's been drilled that is going to be coming online in the next couple of months?

Most of it is the, is the Teco Firm (indiscernible) at Columbia with our horizontal drilling program. So unless we extend, we continue to ramp up as long as we're with our GMX (indiscernible) Valley program but the bulk of it is our horizontal CBM program.

And do you still feel like -- pretty strongly about the inventory with GMX as far as the overall reserves and results? Is that encouraging so far?

Yes very much so. We still are figuring about 1 Bcf and 1.2 Bcf of well grows between the Travis Peak and the Cotton Valley.

The only costs are are in the 1.4 million range. We are continuing to bring those costs down over time as we get more experience. As the operator in GMX has a lot of experience in the areas we are going to try some things differently on the treatment size. We are going to build our location smaller. We're going to use probably different types of rigs or different joint contractors to bring our costs down. So we are very much so very enthusiastic about this program and continue to like it more as time goes on.

Joel Allman. RBC Capital Markets.

A question for Baird. Could you give us an update on the Cherokee base and CBM play and while you're at it, talk about other CBM plays and just kind of give us the highlights and other kind of CBM type highlights you got going?

We had been reporting on the Greenwood County stuff in Kansas. The three out of five test wells we had drilled last year were making about 40 Mcf a day. Now that was to the atmosphere with no back pressure. In order to get better measurement, we installed some meter runs. We installed back pressure on those wells to simulate what you'd expect under operating conditions with line pressures. The (indiscernible) of those wells have gone down. They have not recovered to the 40 Mcf day average that we had two months ago.

But they are continuing to make water. We, at this time, have told people that we thought that we would have a good idea as far as whether we're going to go forward or terminate that project by the end of this year. Based on what's happened, I think it's going to take until sometime in 2005 to get a better feeling one way or the other, whether we're going to go forward or not. The five wells in Chase County are continuing to make about 100 barrels of water a day with very little indication of gas this time so we're just going to continue to pump all 10 of these wells and over the next six months to a year just see what happens.

It's fair to say we're less optimistic than we were.

It sounds like it. And then can you talk about the other CBM type and give us the highlights of the horizontal CBM in Appalachia and then I know you did that one Devoney and Tess (ph) (indiscernible) kind of talk about that a little and you're doing a deeper one I think that was in Louisiana.

That was Mississippi. Gwenville (ph) Fields. Sure the wells that Jim alluded to up in North Central West Virginia, we are very encouraged with the results so far. Originally that well was turned down it was making about 150 Mcf a day against about 105 (indiscernible) back pressure. But since then Dominion who is the production operator in this case has installed a well leak (ph) compressor; that well is up over 300 Mcf a day now. It's continuing to make anywhere from 30 to 40 barrels a day of water.

We think because we only got one pattern with any fairly large area, this thing is going to dewater over time and gas (indiscernible) increase. But we have budgeted three offsets to that well.

Next year, in addition, too, we are continuing to aggressively look at other areas across northern West Virginia, southwestern Pennsylvania. And we have a fairly aggressive lease acquisition budget next year to acquire lands on these new ideas we have, there's Devony (ph) (indiscernible) Shale we already mentioned, Joe. We had a lot of problems, drilling problems, with that well. We really only got one effective leg lateral drilled, one lateral we jumped and all practical purpose (indiscernible) in effect so we've got one 2100 fit lateral drilled. On an extended back pressure test that well made less than 100 Mcf a day. So. Economical standpoint it didn't meet our expectations of course, but when we drilled a vertical well through that same shale we had zero gas.

So we did intersect natural fractures within the shale We are going to try it again as Jim mentioned. Whether it is in this area, immediate area or in a different area. We think that horizontal technology has a big application to the Devony Shale in Appalachia and we're going to keep at it.

The Mississippi well. We are still looking at this thing based on some permeability tests that we recently had done. We're trying to figure it out, if and how long we need to drill a lateral. But that's a decision we're going to make here soon and should have an answer here by the end of the year.

I might say here, Joe, not to the pound the drum here or something but some of this stuff we're doing in the shale and stuff we're doing in Mississippi is and even what we did in Kansas was kind of our own idea. There are certainly other people who drill in the Cherokee Basin but we did some things a little bit differently. So we are not the world's greatest risk takers maybe; but we're certainly trying some innovative things and some of them are going to work and some of them are not. That's not to make excuses. I think what I am trying to tell people on this call is that this notion of nonconventional production is something we're pushing pretty hard. We're very good at it or at least our track record is. We will (indiscernible) from time to time but this would be an increasingly important part of Penn Virginia.

And just to mention one other thing, Joe and I forgot to mention this is, we are going to move into some other geological basins sometime next year, like we did in Kansas. This time I'd rather not disclose where that may be for competitive reasons; but there are some new areas we will be acquiring in some leasehold and drilling some wells next year.

David Kahane (ph) of Friedman, Billings, Ramsey.

I apologize if you talked about this on the Penn Virginia resources conference call; but could you give us a sense, Jim, of acquisition market in the coal space? I know it's been tough -- there's been some large transactions but it's kind of quiet recently. Has the flow of things you're looking at slowed? Or is it just -- is there a discrepancy between buyers and sellers out there that is causing gridlock?

I think it's the latter, David. I was asked this earlier; but I'm very happy to answer -- to try to answer it again. Keith, if I say something you disagree with, feel free to interrupt. Dave, we have looked at in the three years that the MLP has been in existence, I used -- I said this morning we've looked at 100 different coal properties. And I bet I'm pretty close to right. I don't have the count in front of me but it includes every single large producer in central Appalachia. We were only able to bring off one deal and that was with Peabody.

Frankly we thought there would be others to follow with them. It didn't work out that way. It hasn't worked out with many of the others. In fact, any of the others. It's no lack of trying. We've also visited with any number of small landowners in Appalachia and have not brought anything home. Our competitor and look alike Natural Resource Partners who I think is a very well-managed company; I think they are a little bit more aggressive than we are in terms of the prices they are paying. They, too, haven't been able to my knowledge to make any acquisitions in 2004. It's just a tough market. The bigger players, the (indiscernible) the Masseys, the Peabodys have a reluctance to part with coal because it's a control issue in their mind.

They want to keep control and even though they have a lease, even though those lease terms would be terms we think that they could easily live with, there is a reluctance and they don't need the money right now because they're flush with cash.

Also the way these guys have tended to look at things and I don't say this critically, it's just how you look at it. They tended to say "gee, I can borrow money for 6 percent so why should I pay you 7 percent in a lease?" So there's those sorts of things.

There's just been a reluctance. It's because of that and I guess one other thing. Where we would like to be positioned is as well is in the Illinois Basin because we think the long-term that is where the growth is going to be; and Keith and his team have either you can say kick tires or kiss frogs or whatever cliche you want to use. But they've looked at an awful lot of coal in that part of the world.

Our problem there has been, for an MLP, you've got to make it -- if you're going to make an acquisition of any size you want it to be accretive. If you're going to use units as a matter of fact, it has to be accretive.

And most of the Illinois properties we've look at are to be developed and you don't know for sure whether that's three years, five years, eight years. You know it's going to happen. We strongly believe it is, we don't know when. So that sort of precluded us from that.

It's not we're trying, there is a number of things that we are continuing to work on. That's one of the reasons that we put ourselves in a position to get into midstream oil and gas. We brought on a staff to do that a year ago and we're looking forward to pulling the trigger on something there.

That's why we've gotten into this coal infrastructure business. Again, because it's so darned difficult, in our experience anyway, it's so darned difficult to make acquisitions in the coal arena.

So, again, it's not the fact that we're not knocking on doors. We're knocking on every door that we can think of; but damn few people are knocking on our door.

Has the flow -- the flow has been, still, pretty steady the last year? And is that a fair statement of things you're looking at?

Yes, I think if anything, Keith, I would say that you guys in Kingsport and us here in Radnor but Keith is the leader of this effort. It's -- if anything, David, it's not that, again, it's come to us but we've become more intense. We have probably looked at more things. Keith, do you think that a fair statement?

Absolutely. We have a number of things on the table right now, David, that we continue to look at. There is no shortage of those opportunities. It's, however it's stuff (technical difficulty).

Sven Dalpozzo (ph) of John S. Harrold.

In relation to the 400 locations at Gwenville, how many were booked at year end 2003?

I don't know and I will get you the answer but it's not just Gwenville, there are really three fields in Mississippi. Gwenville, Maxie and Baxterville. Baxterville is the one we're more aggressively drilling on right now. My number encompassed all three of those fields. I don't know how many puds we have in Mississippi. But we will figure it out.

Probably we have about a quarter to a third of those booked if I had to guess.

And what would you estimate reserves for a well to be in that area?

Those wells average about -- there's a range between Gwenville, Baxterville, but between 300 to 400 million net.

Have you in relation to operating outside the AMI, have you been accumulating acreage outside the AMI in order to drill your own wells or do you see things not really extending beyond the pilot phase that you're in right now in terms of using your own process?

No, we are -- in the area where we drilled the first well, I think it's a matter of public record that we've got around 20,000 acres of leasehold there and we're very aggressively pursuing leasehold throughout the northern West Virginia. As Baird said, Southern -- Southwestern Pennsylvania even into Ohio.

In relation to that acreage accumulation, do you think that you might see meaningful increase in the number of wells drilled from that compared to your one so far or are you still in a learning by doing phase where we might be looking at more of a 2006?

Well I think it's more that; as Baird said in the budget which is yet to be approved by a board but in the budget we intend to drill three offsets to that well we drilled this year. We will -- you always sort of play these things by ear. If we knock the doors down, we will try to drill a few more. But what you have to do you have to acquire leases number one you have to do a coring program No. 2 to get a feel for the -- amount of gas content in the various coals because it's quite different for the thicknesses and just map them to some degree and you have to be sure that there's infrastructure available to get the gas out.

So those things as a group take time. So this -- the outside AMI, I would think it's an '06 program where you'd see a ramp up I'd say significant and then you'll ask me to define it and I don't want to because I don't know. By then, we should have coring done and half the infrastructure issues addressed and decide how hard we want to run. The harder we've run inside the AMI, the slower we would need to run outside of it. But we are -- we're going to build ourselves a coalbed methane business. This is going to be driven by horizontal technology.

Dan Morris. Aperian.

(OPERATOR INSTRUCTIONS)

Most of my questions have been answered but, Baird, if you could kind of expound a little bit on the Devonian well. Did you try any stimulation on that? Or was it more just science and kind of what have you learned off this first one that is going to alter what you do on the second one?

Well two things, Dan, we're going to drill these things differently. We are going to simplify the drilling process. We used the same technique we used up in the coals up in North Central West Virginia and it's a lot of detail I don't want to get into at this time. Way too much detail. We feel we can do it cheaper just by utilizing conventional directional technology in drilling; and drilling under balance, drilling with an airphone system vs. the way we do it or the way we did it up in north central West Virginia. That's the first thing. We think we're going to be able to reduce our cost. Probably 25 to 30 percent by doing it a different way.

Secondly, getting back to your question of whether we stimulated it or not, we did not stimulate this well. I say in all probability, based on what we learned on this thing, that we would set this next pattern up for stimulation. I think that makes the most sense because of not knowing exactly where the natural fractures are to drill these things, may need some stimulations and predetermined if it was in intervals in those laterals to optimize your chance of intersecting those (technical difficulty). We will do both of those on the next try.

Refresh us how deep were these?

Well in this immediate area, it was around 2500 feet, was the shale. We purposely went into an area where the only shale is shallower. If you look at the Appalachian Basin, at least in the heart of the basin where it's the most productive, it ranges anywhere from 2500 feet to probably 4000 feet. As far as where this next attempt may be, it may be in the deeper part of the basin but it would be in that 2500 to 4,000 foot range.

Ray Beacon of Harris Nesbitt.

Jim, just one more question on the coal side. If you were to mark to market or try to mark to market your distribution to where contract prices are now, I know some of those volumes will not get mark to market but what would $40 to $45 ton coal do to the distribution?

Oh, God. It would raise it.

I knew the direction.

Ray? Let me try to figure that out. And Keith, help me out here a little bit. Typically, a little bit of history. If you'll bear with me for a minute. The royalties that we collect, about 35 percent of them are from Peabody. Those royalties are not price sensitive. They escalate over the life of the lease for the individual two mines that are involved here but they don't escalate as a percentage of prices. The other two-thirds of our leases do. All those of those two-thirds about 15 percent of them are exposed directly to spot prices. So, there it's 15 percent of $60 (inaudible). Excuse me -- 7 percent of $60 is 15 percent of 30 of 666 if I turn on my calculator here. That's about 10 percent of our.

Overall volumes.

Royalty volume comes directly that way. So that leaves the other 55 percent or so coming from contract prices where we -- where the lease is tied to the contract. About -- Keith now you got to help me -- about two-thirds of that has rolled off and is experiencing higher prices or less? Or do you know? Or are you there?

Yes, it's about 50 percent that is rolled off, Jim.

So Ray, what you got there is another 50 percent 55 percent so let's call it 25 percent of these things are still at prices that might be closer to $30 than $45 or $50. So now you sort of do the arithmetic here, 32 million tons. That's 8 million tons so we got another 8 millions tons' worth of realizations to get up to 350 a ton or so, 7 percent of $50 is what I did. And I'm going to lose my arithmetic here. So there's room there to raise distributions some.

I mean you got to now divide that by the number of units outstanding which is 18.3 million as I recall. And you'll get some number of pennies or dimes. You won't get dollars.

I mean I can do the math for you but that's how I would do it.

Ray, this is Frank. I just did it real quick back of the envelope and I think if we sold everything if everything were told at $45 a ton except the Peabody ton of course, which are fixed-rate royalties, you're probably looking up somewhere in the vicinity of $10 million of additional revenue.

So 40 cents you can raise your distributions 40 cents if you did increase your number of units so I'm saying it's numbers of dimes. It's not dollars.

For us the way to grow the Company on the coal side is to increase volumes. And the only way we can increase volumes is to increase the amount of reserves we own that are mined because most of the reserves we own today are under lease -- the vast preponderance are under lease. I don't know if that helps you or not.

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