Ranger Oil Corp (ROCC) 2003 Q3 法說會逐字稿

Good afternoon and welcome to the Penn Virginia Corporation's 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. If anyone should require operator assistance during the teleconference please press star zero 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.

Good afternoon. I apologize for the delay. We had some mechanical difficulties here, I guess I should say electronic difficulties, but apparently it's straightened out.

I'm joined this afternoon by Frank Pici, our CFO, Baird Whitehead, who runs our Oil and Gas division, group, and Nancy Snyder who's our General Counsel. So welcome. We'll get started here.

As you know I generally don't like to and I'm not going to sit here and read you numbers, because the numbers are in the press release, and I'm happy to answer questions about them, but you can see from those numbers that revenue earnings, cash flow, et cetera, are all quite a bit better than they were comparable numbers in 2002, and that shouldn't be surprising because prices are up significantly year-over-year as you again can see from the press release, and production is up a little bit.

It's up about 8.5% on a total Bcfe basis in the third quarter, and about 14% year-to-date. So that combination of some increase in production and a strong increase in prices has, of course, made us, and probably every other EMP company look pretty good at this point in the year. I can obviously answer questions about the numbers but that's really all I to have say about numbers for the moment.

The next part of the press release deals with the oil and gas segment, and we put out a release on the 29th of October of this year that details more than this release some of the things that are going on operationally. Let me just say that a couple of words.

One of the problems that we've had to deal with this year has been that while we've had a lot of success exploring particularly in southern Louisiana, we've had less success getting some of that gas to market, problems with getting gas in line and getting hooked up. We've made some real progress along those lines. There's some real progress has been made, and some of it is detailed here.

The Broussard well, which is drilled right in the city of Lafayette, Louisiana, has been brought online finally. October 1st is when we commenced production. It's quite a well.

It's making about 18.9 Mmcf per day of gas and another 480 barrels of condensate. We have about a 37% working interest net to us. That's a little over 6 -- it will be a little over 6 B's, I guess.

Lost track of where I am in my notes, excuse me. It's about 6 -- never mind. It's about 6 Mmcf per day is what I meant to say, which is about 8% of our production. I apologize here, I'm a little non-plused by this computer problem.

Another success that we've had was in Stella, we drilled three wells there, actually four, all have been successes. We've had some difficulty getting some of those hooked up but two of them on the East side of the Mississippi which ended up requiring drilling a gathering line, putting a gathering line under the river where it's about a mile wide that has been complete. We would expect those two wells to come online late this week to next week.

The third well will come on sometime in December, the fourth well which looks very encouraging is still being tested and would be a 2004 event.

We'll also talk a little bit about Creole, South Creole, another South Louisiana exploration project where we've drilled and completed two wells and we're awaiting hookup there. They weren't part of our guidance and probably won't have any influence until 2004 although there's some hope we could get one of them online this year.

At least as far as those, get the gas to market problems go, we seem to have made some progress there.

We've drilled a lot of wells this year, as you can see by the press release. Out of 140 wells that we've either drilled or participated in year-to-date we've been successful on 136 and if you do the math I guess, that's 96 or 97%.

We had a similar success ratio in the third quarter but in the third quarter, you know, we he who lives by the well dies by the well, and we had a bad one. We drilled a well in Kingsville, which is our South Texas acquisition early this year.

Although the logs looked good when we tested that thing after stimulating it we found water in two of the zones, and that well is not a success, and that has certainly caused us to stop to make sure that the fairly complex geology in this part of the world is something we more fully understand.

We wouldn't have drilled any more wells in the Kingsville prospect in 2003, but it will cause us to be very sure that we're understanding what we're doing before we drill any more in this piece of Kingsville in 2004.

There is within the Kingsville field another look-alike structure which we intend to test next year. So Kingsville cost us, and that was the primary reason for the very slight change, but nonetheless change in our guidance this year which we can talk about in a minute.

In the East, as far as drilling or operations go, we've been fairly successful. We've bought some property in the Selma Chalk in Mississippi, we've been drilling that at a little more accelerated rate than we anticipated early in the year, and that's gone very well for us, we're quite pleased with those results.

In terms of the CBM, in the East, the horizontal CBM in the third quarter, we were able to complete five patterns with our partner, CDX. We would expect to get two or three more down this year, year-to-date we've got 12 patterns completed.

They have committed to us a third rig which we're still quite -- waiting to get online but we hope will be online very soon, and we'll remain committed to us, we hope, throughout 2004, and we're talking to them about committing a fourth rig in 2004. We can't really control that but we're working fairly hard on it.

I don't typically give you well by well or formation by formation kind of talk, in a discussion like this, but I will digress a little bit and just say on one of the wells, because it's really remarkable, that we drilled in West Virginia, and in our nomenclature, we call LCHC 001, from a single pattern, and only about 17,000 feet of lateral, that well is making 7 to 8 Mcf per day, Mmcf per day. That's a very good well, almost by any standards, and certainly by the standards of CBM. That's the best well we've ever participated in since we've been involved in this program.

One other thing I'd just say, a couple of the wells we're going to try to drill this year, we're going to try to drill them in more than one seam. That will mean that a couple of them will have four patterns connected with them. We would anticipate drilling as much as 115,000 feet of lateral in those four patterns. They're set differently, 21 miles of lateral, a fairly significant set of wells.

Capital expenditures for the quarter are detailed in the press release, and again I won't read it to you but it sort of breaks it down. You see the emphasis, as would you expect, is on development drilling, nearly $20 million of the $28 million is going there. The rest of it's sort of detailed for you.

With regard to PVR, the Master Limited Partnership of which Penn Virginia is a general partner, we had our teleconference discussing those results a little earlier today, if you were not on that I'll just summarize it quickly as it is in the press release.

We're basically right on track. We did our deal with Peabody at the end of 2002.

That changed the numbers considerably, production in terms of tons is up, revenue is up, cash flow is up, DD&A is up, and that's had a negative effect on net income but the truth of the matter is, in an MLP, what you really ought to be looking at, in my opinion, is distributable cash flow, and that is up. We expect to make our distribution on the 14th of this month.

Operationally I think everything is going exactly as we would have hoped. Our nemesis in 2002 was something we called Fort Creek. It's a mine that we had leased coal, we had leased through a person who went bankrupt, a company that went bankrupt.

We got it back, we got the infrastructure back. We leased both the coal and the infrastructure. Production began July 30th of this year. We're running at about 45,000 tons a month right now.

A year from now I would hope that number would double and two years from now I hope that number would increase by a factor of four. So we're on course finally there.

We're doing a few small things in terms of Cap Ex there where we're building another load-out in West Virginia. Much like our Virginia load-out, it will stand on its own two feet just from the fees, but our real reason in getting involved in it, of course, was to encourage additional production by our lessees.

Just a little on coal. The markets in the East, maybe more so than in the West, but certainly in the East, which is where we play primarily, are strengthened, have strengthened, the prices are up in the mid 30's, a year ago they were in the high 20's, six months ago they were in the low 30's. So there's been a strengthening there.

Coal prices track with electricity usage to a degree, at least. Electricity usage often tracks with the manufacturing sector in this country. Particularly on the base load side, which is what coal is usually used for.

As the economy is appearing to strengthen, we're looking for coal prices to strengthen or remain at least as strong as they are. So I think there's no -- certainly no bad news on the PVR side. In fact, I think it's fairly good news.

In terms of our dry powder, or capital resources, again following the format of the press release here, as you can see we've got a fair amount of dry powder. We put up a shelf, a $300 million shelf for both PVR and PVA in the third quarter. There are no overt plans to use those shelves for any specific acquisition opportunity that we're looking at, at the moment.

We are looking at several but we're not necessarily -- didn't put it up for that purpose. We put it up to have some flexibility to be able to move quickly if and when something came along.

With regards to our guidance, I will just point out a couple of things, because again I think we've touched in our October 29th release about the change in production guidance from 24 to 26 to 23.5 to 24.5. And we've tried to explain I think an awful lot of that was due to that Kingsville well, which was a set back, no question about it.

Another thing you'd notice, is our exploration guidance is now 14 to $17.5 million as opposed to 15 to $30 million, and that's quite a change. And the reason is explained also in our October 29th press release. Basically, if those of you who've heard me out speaking at these various conferences, and we've done quite a few of them in the last few months, may recall me talking about us drilling some of our, at least one of our higher risk prospects this year.

We had intended to drill into the Vicksburg and something we call Richard King. We had 100% of that thing. It's fairly risky but a very large target.

We were going to do it this year but then got, frankly, cash call on a similar project where we only have a 30% interest, it's also in the Vicksburg, in same general area, also a fairly large target, so we substituted one for the other but our exposure there is considerably lessened, so we've changed our guidance with regard to exploration. There are some other changes in the guidance table but basically, they're a tightening up of the guidance because as we've gotten near the year end we're more confident of our numbers and so we've narrowed the spread.

So that is the end of my little dialogue here, and, Meg and I would be very happy to take questions.

Thank you, sir. Ladies and gentlemen, at this time we will be conducting the question and answer session. To allow everyone the opportunity to ask a question, please limit your time to one question and follow-up. If you would like to ask a question, please press star one on your telephone keypad. To remove your question from the queue please press star two. A confirmation tone will indicate your line is in the question queue. To participate, for participants using speaker equipment it may be necessary to pick up your handset before pressing the star keys. Please hold while we poll for questions. Our first question will be coming from Joe Allman of RBC Capital Markets.

Hi, everybody.

Hey, Joe.

Hi, Joe.

I'm not sure if Baird is around, but my question is about the Cherokee Basin. Can you just give us an update of what you're done so far with the CBM play there and what the plan is for the next 12 months or so?

Yeah, Baird is around, and I think I'll let him answer the question if he wants to.

Joe, we have drilled, we have two different prospect area in the Cherokee Basin in which we have about 45,000 acres today. One area we have drilled five wells, and those wells have been drilled or completed and are currently on test. Three of those five wells are making some gas at this time, anywhere from 15 Mcf a day up to 25 Mcf a day. The other two wells we have yet to see an indication of gas but they are making some water.

The other prospect area we have drilled one well since coal [inaudible] and we wanted to get a good sense that we have some permeability, because as you go deeper in the coal, you have more of a chance the coals are tighter, but we have not seen that tighter coals, and we are making plenty of fluid, and the plan is to drill four offsets to that well between now and the end of the year, the first of which is drilling, and get these wells all in test by the end of this year, beginning of next year.

So the jury is still out at this time. We do have gas on three out of the five wells in the one prospect area but we really won't know anything as far as economic success until sometime first quarter, second quarter time frame next year.

I might just add to that, Joe, in case there's any confusion at all, we're anticipating, this is conventional vertical wells. We do not depend on horizontal for this to work. That might be an upside, we just don't know yet.

Thank you.

You bet.

Thank you. Our next question is coming from Ray Deacon of First Albany.

Yeah, hey, Baird. Just a follow-up on the Gulf Coast. Is there -- can you give me some idea of how the inventory looks now at this point, I mean given that you're five for five this year, what kind of drilling schedule do you think you'd see next year based on the results you've seen so far this year?

Well, we're going to continue to drill in the Stella area. We have a rig currently working. And as I understand they're ready now, based on the operator is to keep that rig busy for going into the beginning of next year. We have three additional prospects, Stella prospects to drill around the same salt zone next year.

Creole, we will follow up with some subsequent development wells next year in Creole, and the [inaudible] of O-10. We also have planned at this time two additional -- excuse me, three additional O prospects, two additional O prospects and one additional J prospect.

So based on the success we've had to date in those areas, it's going to result in some subsequent exploratory and development wells. We're just getting started in Esperanza, so who knows what's going to bear out there, but we have some plans based on what we have seen on seismic data.

We have three prospects in South Texas in Nueces County to build Vicksburg. Probably one of the more important things is our [FENETIC] field. We are going to drill one prospect at the end of this year, it's an amplitude prospect, a little on the smaller side, 1.5 to 5 B's, but we have some larger prospects planned to drill next year, [inaudible] area that are in the 15 to 20 Bcf size, so we have that data in, we're going through some additional processing to make the salt, the picture of the salt a lot clearer, because we're on migration prones as you get close to salt so we're going through a reprocessing to sort that out. We're seeing a number of things to do there and we're very encouraged so far.

And you think your Cap Ex will be at least equal to this year, as far as you know, or --.

Well, I'm going to interrupt there.

Right.

The problem, Ray, and I don't mean to be evasive here, but we haven't put out guidance and I don't really want to put it out now, [inaudible] budget right now.

Sure. Just one more. I missed the very beginning of the call, but have you said anything about the, you know, probable and possible number you see Appalachia as a result of this well looking better? Could that extend to other wells?

We haven't booked any PUDs yet at all with our HPCM. We may at the end but at this point we have not.

Thank you.

Thank you. Our next question is coming from David Snow.

Yeah, could you give me some idea as to what the Appalachian CBM production is and how many wells that's coming from?

The short answer is yes, and the long answer is we're going through briefing books so we give you a good number.

It's about 5 million a day as we speak. David that, is coming probably from one, two, three, four, five, six, seven, probably around 12 wells in which we have various working interests in.

That's your net interest?

That is our net revenue interest volume, that's correct.

And you're roughly 60%?

Well, yes, on our overall deal, yes, but we have smaller interests in some patterns because of the prior agreement that we had done with CEX so we have interest as low as 10 to 15% in a few wells.

What's the average that the wells are making on a gross basis?

Well, if I had to guess, I don't have that exact answer here, but because of the timing of when some of these wells are drilled, some of these wells now are as old as a year and a half two, years old. I'd estimate from probably all those are averaging about $1.5 million a day, would be a guess.

Okay. And I was thinking back to a slide a year or so ago that you had that looked like you got about a 1.75 Bcf's per 800 or 1,000 acre spacing. I'm wondering, is that holding up, and what would it look like with that humungous 115,000 foot of lateral well? Would it go up just basically in proportion to the footage lateral, I guess, is that right?

That's correct. Acreage wise, since our coals are fairly uniform in thickness, anywhere from 30 inches to 60 inches, yeah. As you continue to drill longer footages and drain more area it really is almost a straight-line proportion. Our gas content has some bearing in that, of course, but if you're in a similar area, that relationship pretty much holds true.

Is 1.75 Bcf's per thousand acres a good number for just a single level of laterals?

Yes, sir, that's still holding true, that's correct.

Thank you very much.

Thank you.

Thank you, gentlemen. Ladies and gentlemen, if you do have a question at this time, please press star one on your telephone keypad. If you are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Please hold while we poll for questions. Once again to, allow everyone the opportunity to ask a question we ask that you please limit your time to one question and one follow-up question. Our next question will be coming from Dick Feldman of Monarch Capital.

I have a question about the Selma Chalk. You mentioned that you accelerated drilling there the latter part of this year. I wonder if could you sort of run through the economics of a typical well, and then talk about what type of drilling inventory you have there.

We're going to drill anywhere from 20 to 25 wells in the fourth quarter, specifically Baxterville, [inaudible]. Baxterville's in Marion County, Mississippi. The initial rates of these wells are about 300 Mcf a day. They go on a fairly steep decline because they're considered tight reservoirs. It is a chalk. They are fracked. Drilling and completion cost are around 300 to $325,000. Economics, you're probably -- you're talking about low 20%, low 20's after-tax rate of return at today's gas prices.

Okay.

Probably have -- I don't think part of your question was inventory. I think we've got three or four years of inventory kind of drilling at the same schedules we have been this year.

We brought Baxterville based on about 120 wells, number of drilling locations, when we made this acreage acquisition late last year.

Switching to Appalachia, at your current rate of drilling, how many years worth of horizontal coal bed methane drilling do you have, and if you continue to be successful, how would you like to ramp that drilling up?

We have what we say when we go around and speak is that it's kind of a complex question, actually. Acreage that we control, meaning Penn Virginia, is about 500,000 acres. We guess that about 200 -- we don't guess. We're fairly confident that about 200,000 of them are what I'll call perspective, i.e. seem as though they would be suitable to use this horizontal technology. So if you kind of do the math, 1,000 acres, and we give it a haircut of 50%. So we say there might be 100 B's there how fast you can net to us.

We say that not tongue in cheek but we say that recognizing it's a big number and we think we're being very, very conservative by giving it a 50% hair. Now how fast you go obviously depends on how many rigs you can run. We ran two for most of this year but really one and a half because some of it was deployed off of our property.

We'd like to run, as I said, a third one by the end of this year. We've been promised that rig and we expect it will be delivered promptly. And we would expect sometime at the end of the first quarter, just to pick a number, that we might be able to run a fourth rig there.

Ideally you could run more than that. You've got to have permits, you've got to have infrastructure, you've got to be able to dispose of the water, but we would surely like to be running four, maybe five rigs, but three or four rigs for sure in 2004.

Are you trying to acquire other acreage in this region?

Yes. We have an AMI that we share with CDX that covers 16,000 square miles that's virtually all of central App. We've got some options on some various acreage inside that AMI and we've taken some acreage outside that AMI.

On the acreage outside the AMI then you would use that CDX technology?

I didn't say that. We would not have to. It's very good technology. We would use it if it made sense to.

Thank you, gentlemen.

Our next question is a follow-up question from David Snow of Energy Equities.

I'm wondering, are you still generally doing the profile of four-year depletion of the CBM, or are you drilling less initial front end on average and extending that over seven years? What's the game plan on average going forward?

Well, the geology -- Baird, go ahead.

I think the question is, the life of the well, is that what you're saying, Dick?

Yeah, how fast are you going to deplete them on average? You could do them over four years or three and a half years but it is a function partly of how much lateral you drill I guess. What's the expected average?

That correlation doesn't necessarily hold. You could drill as much lateral as you're mechanically able to do, and you run into operation trying to push these things too far because of fiction of your pipe alongside the bottom of the borehole itself. But the three and a half to four years is for things we will do almost 99% of the time is still valid.

Okay. And I'm wondering, you're drilling eight to 12 wells this year. Would you double that next year with the average of at least three rigs, do you think?

We would like to. We would like to more than double it, but we really don't have the budget yet. We don't have the third rig yet, we expect it. We sure don't have the fourth rig yet but we have had conversation with CDX and been assured we could get it. So it gets a little bit speculative, and we haven't put out guidance yet for '04. I don't mean to be evasive, but that is the facts of the matter.

Earlier I was using a profile that was something on the order of, I think, $2.7 million a day in the first year and then $1.3 million and dropping in half each year. Is that still a good average for what you've been doing in the wells this year? You mentioned one and a half, that includes some older wells. What's the year one average for the new ones?

That what you just said is correct on a brand-new well and a thousand acres, the 1.75 Bcf. Since we have various acreage sizes for all these patterns we drill, some are more, some are less, but the 50% decline after a flat production of the 3 to 6 months is still a valid production profile for one of these wells.

Thank you, gentlemen. Once again, if you would like to ask a question, please press star one on your telephone keypad. Please keep in mind that to allow everyone the opportunity to ask a question, you must limit your time to one question and one follow-up. Gentlemen, there are no further questions at this time. Do you have any closing comments for the teleconference?

Not really, other than to say again that, as always, we appreciate the fact that you could all take your time to listen in. We hope that we provide a service here and provide you with some good information, and just thank you for your participation.

Thank you for your participation, in today's teleconference. You may disconnect your lines at this time and have a wonderful day.