Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Jim Dearlove - President and CEO

Frank Pici - CFO

Keith Horton - EVP

Baird Whitehead - EVP

Jim Dean - Investor Relations

Analysts

Scott Hanold - RBC Capital Markets

Joe Allman - JPMorgan

Richard Tullis - CapitalOne

Steve Berman - Pritchard Capital

Jeff Davis - Waterstone Capital

Penn Virginia Corp.(PVA) Q4 2007 Earnings Call February 14, 2008 3:00 PM ET

Operator

Welcome to the Penn Virginia Corporation, fourth quarter conference call. At this time, all participants are in a listen-only mode. 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, President and CEO. Thank you Mr. Dearlove, you may begin.

Jim Dearlove

Thank you Robin, and welcome and good afternoon. I'm joined here today in Kingsport Tennessee by Keith Horton who runs our coal segment of PVR, as well as Forrest McNair, who is the controller of the corporation. In Houston, we have Ron Page who runs the mid-stream piece of PVR. And here in Radnor with me, is Baird Whitehead who runs our oil and gas business; Frank Pici, who is the CFO of PVA and PVR; Nancy Snyder, who is the general counsel of all of PVR and Jim Dean who is our Investor Relations person.

I would remind you that over the course of this call, and several of us who will be speaking, we are viable to make forward-looking statements and I direct you to the disclaimers that are contained in the press release covering that sort of thing.

As you know, its not been my practice to necessarily follow the release word for word and I certainly don’t want to read it to you and this time we’re bounce around a little bit more than normal, but I will just try to keep it as orderly as I can.

As you can see from the release, Penn Virginia Corporation enjoyed a very good year from both the production and reserve growth standpoint, frankly from the cash standpoint as well, I would say. In fact, production for the year was just under 41 Bcf equivalent, a 30% increase and improved over 2006 and proved reserves grew 40% over 2006 to 680 Bcfe.

Operating cash flow, again as it says in the release, was $302 million or about 15% over the last year. Net income was lower than last year; it was just under $51 million, which is lower than the $76 million reported in 2006. However, this is due to an increase in derivative expense; that’s where virtually all of that comes from, that expense results mainly from changes in the evaluation of unrealized derivative positions, most of those expenses are the non-cash reserve of accounting for market-to-market of variances that carryover from PVR or MLP.

And Frank will address the hedge program, as well as the derivative issues in a few minutes. We’ll try to give you a different picture of net income, using something that we called adjusted net income which excludes the effects of those non-cash charges. That number was just under $70 million for the year or about 15% over 2006. The fourth quarter is a mirror of the year. Production was up 25% and operating cash flow was up about 14% over the corresponding quarter in '06. Net income was down for exactly the same reasons and adjusted net income was up from $7.1 million to $12.8 million for the quarter-to-quarter comparison.

The operating income or PVA, the entire consolidated operating income was $193 million or 13% over 2006. In the released details for you, the more important factors that affected operating income and operating cash flow, both positively and negatively, obviously we will spend some time addressing cost issues etcetera here in a minute.

Basically however, the higher oil and gas production and the higher processing margins at PVR Midstream, virtually offset by higher expenses across the company and a slight lowering of operating income from PVR's coal and natural resource segment, determined what our operating income was for this year and as I said it was up above 13% over last year.

Net income for the fourth quarter was heavily influenced by this derivative expense, again these are basically non-cash changes in valuation of unrealized derivative positions and Frank will speak to that.

What I am going to do now is depart from order of the release and put off oil and gas operations for a minute and just get PVR out of the way.

PVR, as you know Penn Virginia Resource Partners, LP is an MLP that we formed seven years ago. Its general partner is now owned by something call Penn Virginia GP Holdings, an MLP last year, right at the end of 2006, in which we own 82% of. It, in turn, owns the general partner and incentive distribution rights, and 42% of PVR's. So what happens at PVR flows through directly to PVG and then to us. And we, in order to save space, this release is already 16 pages long, we direct you to the website that contains the releases for both PVR and PVG. And they are easy to get to and easy to navigate through. I am not going to spend a lot of time, but I am going to give you a little more detail on the paragraph that’s in the release. And that is to say this, the most important thing, I think, in a MLP is distributable cash flow and for PVR and as I say that, that passes then through PVG and on up to us.

The cash available to distributor, limited partners last year was up, 20% to $120 million, that was a new record for PVR and it also set a record for operating income, which was up 14% or almost $118 million. It has the same issues, in fact it's the driver of the issues with regards to adjusted net income versus net income. So, as is reflected in our numbers at PVA, PVRs adjusted net income was much higher than the preceding year, $89 million from $67.7 million, but net income was a little bit down, because of the issue with those derivates. Likewise, the quarter was a mere image of the year, record levels of distributable cash flow on operating income, high levels of adjusted net income, but lower on net income.

And then finally, on that subject, just a little bit of color. PVR mid stream had a very good quarter and build and is bringing online, any day now or any week now, a new 60 million a day plant that will augment what it’s been doing at some of its existing facilities in the Texas panhandle and perhaps more importantly the PVA is also very close and we would expect that the plant to be available and to be operated at the end of first quarter and hooked up some time a little bit after that. And anyway, that plant is an 80 million a day plant and it will ultimately process most of the gas produced today by PVA in the Cotton Valley. It will also handle the gas produced in our area of mutual interest with GMX. So that should be very good news for PVR and PVOG, going forward.

I think the only other thing I'd say in this, is with regards to PVG. They make distributions to us, they are going to make a distribution on the 19th of this month of $0.32 a unit annualized, and that’s $1.28 a unit. What all that means is that it’s about 8% over what it was for the third quarter of '07 and about 33% over last year. Translating that into money, it would represent that we held this distributions flat, $41 million at pretax cash coming to PVA and over the course of the year the value of the units that PVA holds and PVG is increased by about $300 million, to just over $800 million.

So with that, I’m just trying to dispose is the wrong word but explain and cover the MLPs. Now the heart of the matter here is oil and gas and now I'll turn to oil and gas operations, before I turn it over to Baird.

As I said in my opening comments, the proved reserves in the oil and gas segment increased 40% in 2007 over 2006 to 680 Bcfe. Roughly two thirds of that increase came through the drill bit. We did have a successful acquisition program but most of that drill was generated through the drill bit. This would mean that we've replaced 628% of our production or again through the drill bit through extensions, discoveries and addition 445%. And as I said, that most of that result was the result four negotiated old time acquisitions, each of them in one of our core and important areas.

The release details for you, the revenues, the operating income, and the various expense categories in the oil and gas segment and as you might expect a 30% increase in production; these are higher revenue, higher operating income but also causes expenses to increase. I want to read each and every one of these to you, but we are quite happy to talk about them as things unfold.

With that, I'll turn over to Baird for a more detailed discussion of oil and gas ops. Afterwards we are going to Frank who will begin to start reviewing numbers. I’ll amend that. I guess I'm going to have Frank talk to you a little bit, Frank Pici, our CFO, about some of the expenses and some of the numbers that are in the release.

Frank Pici

Okay, thanks Jim and then we'll go to Baird. Just a couple of things to touch on in the release. I guess one would be the derivative impacts. We see a very volatile number in our income statement these days, since we switched over to mark-to-market accounting some time ago and as a result of that of course we've got to reflect any changes, from one quarter to the next, in the value of our open positions and the fourth quarter had caused some fairly noticeable volatility. As Jim mentioned, most of that came through the midstream segments that we report, the PVR Midstream segments that have to be consolidated. And that was effectively, most if not all, of the derivatives expense that we've reported for the quarter. That's really a result of the run up in oil prices and the effect that run up had on the open position that PVR Midstream has taken on to mitigate its processing margin risk. On the oil and gas side, we actually had some benefit and there may be a way to express that to you. And by the way, what we do is, we give out the adjusted net income number, now. That takes out the mark-to-market impact and puts in the summary of the cash impact of that hedging and we believe, puts net income on perhaps a little more understandable quarter-to-quarter or year-to-year type of comparison.

But then, looking at the impact on the quarter and the year for the hedging, I'll look at it, first in the context of the Midstream segment and in that segment we actually had an adjustment to our stated processing margin. And the way I look at that is the midstream segment had a fourth quarter processing margin of about $30.8 million, if we adjust that for the cash payments on our hedges that goes too little over $23 million, so it’s about a $7.6 million reduction. But if you look at it on a processing margin per MCF within that volume basis that takes the margin down from [1.81] in MCF to [1.36] in MCF. But when you compare that to the prior year that [1.36] adjusted on the same basis would only have been $0.84. So it’s a very dramatic increase quarter-over-quarter, even given the hedging payments that we made during the fourth quarter.

For the full year, that affect on the midstream margin was $1.13 and net of hedging payments versus $0.82 from 2006, so again very impressive increases year-over-year.

So quite a lot of that weighing, even though we show some fairly large derivative expenses on the income statement, when you net them back, the cash impact of that down through the operations of PVR Midstream, we still have very impressive results.

I'll switch gears a bit and look at the oil and gas segment. Maybe the best way to express that is the impact our hedging activity had on our price realizations and for the quarter, natural gas is pretty much all that we hedged. We don't have any real significant oil hedging positions out there at this point. But the impact in the fourth quarter on the natural gas hedging positions has increased our effective realized price by about $0.37 in MCF equivalent, and then for the full year it was about $0.38. So, it's impressive increase in our realized price. Again, we actually received the cash on those gas hedging positions we had.

So, when I look at going into 2008, we do have hedging positions on both segments of the businesses in place for 2008. I think for the midstream side we've got about 60% to 70% of our net NGL production and net inlet gas volume hedged.

When I look at oil and gas side, I think we are running roughly 35% to 40% hedged on that side, as well. Actually on the oil and gas side, we've got some volume hedged into '09 as well. Not a whole lot but we are looking at increasing positions as we go through time here, so that number will go up overtime. Jim, do you want me to speak to guidance now or?

Jim Dearlove

No, we'll end with guidance.

Frank Pici

And Baird, if you walk us through operations. I’d remind you that we had an operations release yesterday as well and I suspect there you will be talking from that as well.

Baird Whitehead

Rather than focusing on what we did in 2007, I think probably more important is to speak on what we plan on doing in each one of our play types in 2008, and let me first start with our Mississippi program, our Selma Chalk program. As you know, it has been primarily a vertical program. To-date, we drilled two horizontal wells, in late '06 early '07. Those two wells continue to considerably outperform a vertical counterpart, and in fact the well we drilled in Gwinville has made to-date almost four times what you would expect a vertical well for the same time period. In Baxterville, we have made four and half times more to date than a vertical well in that same field. So as you can see, the results of these horizontal wells are very, very encouraging.

We have drilled two more horizontal wells, both of which we are in Baxterville. We’ve gotten at 3500 feet laterally in both of them, utilizing an H&P’S FLEXRIG. We have not yet completed those, but we will start completion on both of those wells. and soon to be and will perform anywhere from a seven to eight days frac job on both of those wells. So the plan is, just to keep that horizontal rig for the rest of the year, moving back and forth between Gwinville and Baxterville and also to keep one of our vertical rigs also drilling in front of it.

But in any case, we are extremely encouraged with the result and we think going forward, it’s going to continue to add, at an increased rate as you would expect on a production side.

Our Appalachian horizontal CBM program, we will continue to run with a minimum of two horizontal rigs. We have 14 net wells budgeted for 2008. It's still one of the higher economic things that we can drill. Those wells continue to meet our reserve expectation with rates of returns in excess of 50% after-tax.

On the downside, which has our activity limited, we continue to have some problems of getting drilling permits because of the act of the coal industry, but we also continue to talk to some of these coal companies to see if we can come up with the global agreement to slowly minimize these interruptions to give more general permits in inventory so we can continue to add some rigs.

One thing we've not talked about in the past is that we have a joint project with CNX Gas in Northern Virginia; it's in Buchanan County, Virginia. It's a 50-50 deal. Tentatively we're going to drill 50 wells down there with CNX Gas in 2008, its about 20 net because some of the wells we have less than 50% interest in, but in any case it is something new that we've not talked about in the past.

On the Devonian shale, which is another one of these hot topics in the business, speaking with Mason County first. We have drilled our two Mason County wells, one of which we had at about 2600 ft laterally and other one, which had about 1600 ft. One has been completed. It is currently cleaning up after fracs, since it was just fracked last week. It's too early to report in this time, but in any case it appears to be encouraging.

The second well, we should frac in the next day or two. We are encouraged enough that we are starting to kick up right away to get this gas out not only from these two wells, but more importantly, a development joint program which we will initiate sometime this year. And we've also renewed a leasing effort in this area to continue to add to our approximate 8,500 net acre position.

In Boone County, we drilled one horizontal well in the lower Huron; we drilled one vertical well down through the Marcellus. The vertical well we completed in the Marcellus and the lower Huron, we had some operational completion problems in the Marcellus, that well had tested in the Marcellus and the lower Huron, admittedly there was very little gas coming out of Marcellus, because of the problems we had, but it tested about 200 MCF a day on the horizontal well, under a longer term test it's making about 300 MCF a day. One thing I need to remind everybody of is that there are some tight-end zones up the hole that we will go ahead and complete in the vertical well to get some idea of the potential of the vertical or to get just some idea of the potential of the tight-end zones. This is a 30,000 acre lease plus or minus. It is undeveloped, so there could be a lot of upside just on the tight-end type stuff also.

On our mineral fee acres, down in Wyoming County, we have yet to drill that well, we've got to get a [starter] rig, because of the depth, but the plan is to try to get that thing explored sometime in the first half of the year. We've got 70,000 acres of mineral fee; we think it has potential on our acres, because vertical wells were drilled in and around that area back in the late 70s. So in any case, we have to try it. We think there is sufficient gas in place, so something hopefully we can report towards the end of the year.

There is not a lot to speak about concerning the Marcellus. In general, I can tell you that we have initiated a leasing effort up in Pennsylvania like lot of the other companies you have heard about. It’s not only a grass roots effort, but we are approaching it from a little bit of a different twist, as we are making an attempt on gaining some JVs underneath some shallow operators, shallow production type operators. And then we’re going to try to approach that way. So, in any case, we still think that we can at some point in time get a substantial acre position and initiate testing in the Marcellus.

In the Cotton Valley, oil wells continue to meet our expectations. We continue to drill the four wells within the GMX, AMI, two rigs outside of GMX, AMI on the 100% acreage that we acquired most recently with the two acquisitions. The 20-acre down spacing is working, is working well. Last year we had about 90 Pods in the Cotton Valley because of that 20-acre down spacing program and the results and the success to-date that PUD inventory has gone up to almost 280 in Cotton Valley. So, in any case, the 20-acre program is working very well.

As I said earlier we are exploring opportunities on the two acquisitions, the acquisitions and especially that is adjacent to phase 2 are better Cotton Valley wells are in general. We are pleased with the results today, and we will continue to drill quite a few wells on that acquisition in 2008.

On the Lower Bossier horizontal well, we will get that spudded probably in the second quarter now versus first quarter. We are trying to get a vertical well drilled down through it for some pilot hole type information before we spud the horizontal well. But again, we are as enthusiastic about that as ever. To remind you from a resource standpoint the Lower Bossier has about 150 Bcf for every 640 acres and we also think there is potential in the Upper Bossier which we think is about another 50 Bcf on top of that. So speaking about the Bossier in general, it is shale. It is higher pressure in the Cotton Valley, but even can take 20% of that resource per section, we are talking about 40 Bcf gross. So in any case, something that could add to us in the future.

On the Granite Wash, this is a play type that we have not talked a lot about, but it has become a lot more promising here in the last quarter. So we have drilled one horizontal well our self. That well was turned in line just after the first year, it tested initially about 3.5 million a day and about 300 barrels of oil a day. We are participating in two more wells in the same area with a 33% interest. To remind you, we have approximately 9300 net acres in Washita County, Oklahoma. In this Granite Wash play, we think we have around 30 net horizontal wells. If you use 4 Bcf net, which we think is on the lower end of that net to Penn Virginia, after royalty, you can do the math. We think you could have potentially about a 120 Bcf of opportunities for us in reserve adds over the coming two or three years.

The plan is to drill 6 net of these wells in 2008. On the shale front, on the Woodforde we have not talked a lot about that, we've got north of 40,000 net acres between Pittsburg and McIntosh Counties in Oklahoma, as a matter of fact, this is on a more the end of the Fayetteville, but the southern Pittsburg County is just north of some of the recent activity by some of the players in which positive results have been reported.

The other area is in the Anadarko Basin, I'll prefer not to disclose where that is specifically this time for competitive reasons that it is our plan to drill around 4 gross wells this year probably around 1 to 2 net depending on working interest, 2 of which will be in the Arkoma, two of which will be in the Anadarko Basin.

In Fayetteville, in fact to this day we have drilled nine drills almost 20 net wells. We have operated four of those wells, we have seen activities across the nine wells of anywhere from 200 MCF a day through a million and a half a day. The last two wells that we drilled and in fracked are performing better than what we had seen on some of the earlier wells we drilled or participated in. We've got significant amounts of load water yet to recover. But in any case, we are somewhat more encouraged on these last couple of wells but the next two wells we plan on drilling will determine whether we stay in a play or exit the play.

One other shale is the Bakken, we've not talked a lot about that. We've got roughly 40,000 net acres between Dunn and McKenzie counties. We have a approximate 35% partner, we will drill a couple of horizontal Bakken wells in the first half of the year, to get some idea of the potential of our acreage and after which, we will either ramp up that activity or exit that play also.

And lastly in the Gulf Coast, activity is volatile in the Gulf Coast, our Cotton Land wells, even though they have declined, continue to make about 25 million a day gross; we put those wells on a compression which has increased our expenses in the fourth quarter to some extent on the compression side. We may get another well drilled in that field in 2008. We have some other wells to drill, some amplitude prospects to drill in our Creole field, which we have drilled under the last three or four years.

There is probably a better chance than not that we will also get a well spudded as an offset to that [Lafayette] well that hasn't been up in the airs as far as what's going to happen, but it appears that our partner wants to go forward. When it gets spudded is yet to determined but we think, we'll get spudded this year sometime. Since it’s a deep well, it probably would not have any impact until next year. But this will be an offset to the Discovery well that McMoRan drilled and turned inline. I think it was in September of this past year with an initial rate of about 40 million a day and about 700 barrels a well a day, and we have the right to participate 25% in this direct offset. So, that could be material too also going forward. But in any case, you can see we’ve got a number of things steered up, we got a backbone of good development opportunities between the Cotton Valley and Shale and horizontal CBM and things we're doing in the Mid-Continent and we are encouraged with whatever opportunities we have on the table.

Jim Dearlove

Well I’m certainly glad I mentioned we're going to have forward-looking statements. Thank you, Baird. I think that the release talks about the past you've given everybody on this call and at least pulled back the curtain a little bit, so that they can see what we are up to. Frank, I think you wanted to then talk about guidance.

Frank Pici

Yeah. Just a little bit thanks. And just to kind of ducktail what Baird said given the program we've got, I think if you look at the guidance table we've included on page 15 of the release and as we've got the production guidance there and we do expect there to be a noticeable increase in production. And I think this is unchanged from what we had issued some time ago when we announced our capital program for '08 on the production side. So, there is really no change there.

There have been a couple of changes not with respect to the operating expense guidance and the DD&A guidance. With respect to operating expenses, you probably saw on the release that we had some heavier expenses in the fourth quarter, relating primarily to some water disposal costs, largely in east Texas, and then some down hole maintenance that was a little more broadly dispersed throughout our operating areas.

We have taken a look at that again with respect to what we think will happen in '08, and have pumped up our guidance a bit on the cash operating expense side is now ranging in the $210 million to $230 million range. That will vary, based largely on how we get the water disposal issue in east Texas resolved. And we expect that to happen sometime in the first half of the year.

With respect to DD&A, you'll see we had an increase there in the fourth quarter, as well, that was largely a true up of some of our fields as of year end and also reflects the migration of our production base to a little bit higher cost area than we've historically had.

It also reflects the sale of some production we had to MLP that was effectively not burdened with DD&A. So that used to help rate, doesn’t only help our rate going forward. But factoring those kinds of things into the rate we thought it was prudent to increase our guidance on the DD&A side some what. It’s now ranging in the 250 to 265 area.

So you'll see that with respect to capital expenditures we've kept that guidance as we showed you when we announce our '08 budget. We did I think mention, if we have not mentioned here, that if you take the '08 CapEx of 520 million and you back out the acquisition that raises for about $432 million of '07 CapEx, so the '08 organic CapEx increases about 10% year-over-year.

When you take a look at the coal and midstream segments, just to switch gears to that for a second, we have included in the coal section some increase in production there largely driven by the switch deal Illinois basin on the coal side that will have the implication of reducing the overall average royalty per ton from what PVR realized in '07 was largely driven again. Depreciation on that segment will go up some again, as a factor of having more production from higher cost basis areas of more recent acquisitions.

On the midstream side we were reflecting the increase in throughput volumes as a result of the new plant Jim talked about in East Texas, which will also benefit our East Texas oil and gas operation. And there is a new plant in PVR midstreams Beaver/Perryton complex in the panhandle of Texas as well that will of course serve to increase volumes quite a bit year-over-year. Thus, we will have corresponding increase as cost for corresponding increases in both operating expense and in DD&A. We reflected that in the guidance.

I guess, the only other thing I would like to hit on the corporate and other segment is our G&A expenses. Again, we had a heavy fourth quarter as a result of some adjustments for both employment and compensation-related items and also something related to finishing up our new systems conversion that we've completed now.

And when you look at the guidance for '08, you will see that the expected G&A expense there sort of normalizes back down if you will, as lot of the one-time things we had in '07 especially for the new system tends to get through our expense structure.

When you look at our debt levels, our debt levels are expected to go up. The guidance reflects that as a result of the capital spending program we've got in place for this year and that of course will tend to increase our interest expense as well.

So with that in mind, Jim, I think I have covered the key points.

Jim Dearlove

Thank you. Frank, I think that was good. And so with that, I don't have some cushion though to end on, I'd rather just say we tried to give you a pretty good view of where we are and where we are going and I'd rather from hear you now. So Operator, if we could we'll take some questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question today comes from the line Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Thanks, good afternoon.

Scott Hanold - RBC Capital Market

Thanks, good afternoon.

Jim Dearlove

Hi, Scott.

Scott Hanold - RBC Capital Market

Hi, Baird, could you talk a little bit about that Gulf Coast well that I guess unexpectedly went off, could you kind of give us more detail on what happened there and I guess what the status on that is right now?

Baird Whitehead

You are talking about the offset in the [fluid], Scott.

Scott Hanold - RBC Capital Market

No, I am sorry, I guess your Gulf Coast.

Baird Whitehead

Yes, I am sorry the South Texas well, that was in our Fayette field, it was making about 4 million a day, it's been an excellent well. I don’t know exactly what it has made in the (inaudible) but it has made 3 Bcf plus and it watered out almost overnight. We have pinpointed the problem to some extraneous water. We had to work over it back on as soon as we speak right now to squeeze it. Which means to get this water squeezed off and re-perforate in its own and we think we will get it back, can't guarantee you when we are going to get back off 4 million a day. But it appears not to be, a depletion associated with the reservoir self, it just appears to be some adjacent water that just got joined into the well because of some primarily bonding on the [cement] problems.

Scott Hanold - RBC Capital Market

Okay. So, you are hoping to get that back during the quarter, is that right?

Baird Whitehead

Yes, I mean I think we'll finish up this work over here in the next week or two. So, we should get it back in line, assuming it produces okay, back in sometime in early March.

Scott Hanold - RBC Capital Market

And can I ask what your current production rate this year?

Baird Whitehead

Its around a 120 million a day, would be a good number right now.

Scott Hanold - RBC Capital Market

Okay. Around 120, is that would include Granite Wash well, is that right?

Baird Whitehead

That’s correct.

Scott Hanold - RBC Capital Market

Okay. And so, when you look at the progression of production ramp, where do you see yourselves? I know you guys don’t give quarterly expectations out there. But where do you kind of see it going into early into second quarter?

Baird Whitehead

Well, up to some extent, to a large extent not to some extent, its going to be dependant upon the start-up of our plant. To remind you that plant in east Texas will be recovering, I cant remember exactly what it is, but it is about 1000 barrels a day of liquids. So I would add even with the shrink, net of the shrink, I think it's adding about 5 million a day if I'm not mistaken, something like that, or more. So, to some extent, it depends upon the start-up, it will be probably in the mid-120s, if I had to guess, early second quarter.

Scott Hanold - RBC Capital Market

Okay, that's helpful. And then the east Texas, could you talk about the PUD wells you booked, I guess, you said there is 280 PUD wells that were booked, how many of those are 20-acre spaced wells?

Baird Whitehead

Almost all of them now are in 20-acre space. We had all of our wells last year booked on 40-acres space, and so, because of the success of the 20-acre program it's pretty hard not to go ahead and not only keep the 40-acre wells we had, of course, but just to put 20-acre wells in between. To remind you, there are still a large inventory of probs and possibles out there, and we would have that three-figure reporting down here and probably in the next two to three weeks. But in any case there is still lot of probs and possibles in inventory.

Scott Hanold - RBC Capital Market

Okay. And then can you say how big the PUDs you booked were, are they like 1.3 B-type PUDs out there?

Baird Whitehead

We based it more on direct offsets this year, because of performance in the area, but I don't have the number in front of me, but I'd say it's about 1.2 average.

Scott Hanold - RBC Capital Market

Okay. And if I could just take one more question.

James Dearlove

Let me just, Scott let me just one another things, it's actually harder than that, one thing I forget to tell you is, we booked liquids in our PUDs now and liquids add about $180 million equivalent gross per well. So it's probably as close to 1.4, could be the average well on a [per se].

Scott Hanold - RBC Capital Market

Okay with the liquids, okay good. And just one more question I need to take, this as far as your drilling activity, I think you budgeted somewhere if I'm not mistaken around 150 wells for '08 and obviously, you drilled a significant amount of wells just with six rigs in the fourth quarter. Can you kind of speak to what your plans are as far as if you continue with that rate? Would you plan on that increasing activity or would you potentially slow it down during the year?

Baird Whitehead

I think the economic conditions will dictate at that time. One thing we have planned is continued improvements in drilling efficiencies and I think we talked about this in the past which once took 15 days or 20 days drill and spud that. Now we're down in the single digits. In fact we've gotten some holes drilled as quickly as seven days. So it's a lot of wells but the only thing I can say is, I think the economic considerations at the time will dictate whether we continue now on something. One thing that will slow it down is a Lower Bossier horizontal well, I mean that old well probably be 30 to 45 well, so that will slow down the Cotton Valley a little bit and we still have planned a Cotton Valley horizontal well to drilled sometime this year. So that would slow it down a little bit that I can see as maybe drilling a few more than 140 net wells in 2008.

Scott Hanold - RBC Capital Market

Okay, thank you.

Frank Pici

Hey, Scott, one of the plan I want to make, this is Frank. Normally, I don't break-in like this, but I meant to make this point, when I talked about the guidance. But when I talked about expenses for these taxes and I mentioned that we don't expect them to go down much. Part of that is having this arrangement for the plants, the processing cost of the plant, while that's only one side of the equation. Of course you'll see a pick up that I didn't mention, I’d like to make sure I mention here, on the NGL side. So, we are going to get a higher margin on that production than we are getting currently, as we don't that pick up now on the NGLs. So I just want make the point that even though our expenses look like they are going up, there is going to be a higher margin associated with that production. So that's, a [healthy] economic thing to understand

Scott Hanold, - RBC Capital Markets

Okay. Thanks, that good. Thank you.

Operator

Our next question comes from the line of Joe Allman with JPMorgan

Joe Allman - JPMorgan

Hi, good afternoon everybody.

Jim Dearlove

Hi, Joe.

Frank Pici

Hi, Joe.

Joe Allman - JPMorgan

Yeah, Baird on that one Granite Wash horizontal. I am not sure if you talk about the costs, could you talk the costs to drill and complete that well, what you think costs are, going forward?

Baird Whitehead

Those wells are expensive, because we had a couple of sidetracks, but we think on routine basis is based on what our partners doing is $7 million to $7.5 million gross is probably a good number, if not little bit less than that.

Joe Allman - JPMorgan

Great, and then – okay and then at Baxterville in your operation up there you said, you had two dry holes in the fourth quarter, is that typical kind of stuff or is anything unusual on that?

Baird Whitehead

In Baxterville, occasionally we get caught up in some faults in the zone - the chalk itself is only 30, 40 feet thick and sometime we get got up in a fault that’s folded out and we find its actually cheaper to gather the [sub-surface] information based on the drilling and just go ahead and drilling the well rather than trying to the side track, but it occasionally happens, not very often but occasionally.

Joe Allman – JPMorgan

Okay, got you. And then that joint venture with CNX Gas, well what is the target for that joint venture, what's that formation?

Jim Dearlove

It is multiple Pocahontas seam posts.

Joe Allman – JPMorgan

Okay.

Jim Dearlove

There are 5 or 6 or 7 and I can't remember all the names. But there is multiple seams, this are vertical wells by the way they are not horizontal. And they may crack anywhere from 5 to 10 zones, 5 to 10 seams.

Joe Allman – JPMorgan

Got you. And then can you just make a comment on what are you seeing in just overall in your various basins on drilling and completion costs. What are the trends these days here?

Jim Dearlove

Well in east Texas we are seeing it come down. We just negotiated a new stimulation agreement. We brought our costs down, maybe, I think it was almost 10%. We are seeing cementing costs come down somewhat. We are seeing rig rates come down 5% to 10% in east Texas. So overall the cost structure appears to be coming down somewhat in east Texas. In Appalachia, because of the tight wells we drilled horizontally and those being under longer term contracts with CDX and their rigs, those costs stay fairly flat. Mississippi, since we have gone to the horizontal concept using a flex rig of H&P's on a per day basis we have gone from drilling those wells from turnkey on a vertical program with a private contractor to now a day work contract horizontally. So, it is pretty hard to say going forward what those costs are going to be. But we are drilling on well-to-well basis. So, I would assume depending on demand that they may go up, they may come down.

In the [Midcon], we really don’t think, I don't think they have changed a lot based on what I have seen again. We really don't think, I don't think they've changed a based on what I have seen again, we are unique in what we do there, are generally horizontal harsh warm cold wells and now there is Granite Wash program until we get some more of these under our belt, it's hard to say. But they don't appear to be changing. And south Louisiana, I think you will see costs come down there, Day work rates on our rigs,

different than what you may see out in the water, but land rigs, deeper land rigs, surely coming down somewhere in south Louisiana, so some of the wells we may drill there I think will be a little cheaper.

Joe Allman – JPMorgan

Okay. And that’s helpful and then just lastly the higher operating cost you saw in the fourth quarter, how temporary are those costs and when you see those cost falling off?

Jim Dearlove

Let me approach it by category on the sub surface maintenance that Frank talked about, that kind of stuff typically is discretionary. We do things to try to enhance production and with expense workovers, doing restimulation, those kinds of things you see a hopefully a production benefit by that kind of stuff. That you can sort of turn it on, turn it off, as you want to. We are going to continue to do those kind of things if we have the opportunities in front of it. On (inaudible) well for instance; South Texas well those are the one, this is an expense work over. We want to do it, have to do it just because the sheer amount of remaining reserves justified, but there are something's that will go away like maybe in our (inaudible) on some of the sub surface maintenance we do there, some of the sub surface maintenance we may do in east Texas. It is volatile, because we operate on gas lift there and sometimes you’ve got to change that gas lift valves and it takes a rig, so it's volatile. And compression expense, it went up this year primarily this last quarter because we --compression we set in our Cotton Land wells which is expensive compression but again it clearly helps the production rate to some extent also and east Texas. On the SWD's, which was a fairly substantial expensive in the fourth quarter. We will see those costs come down. We have things in motion to drill or re-complete two disposals wells in Phase 2. We already have the water-gathering system in place there. It is just a matter of getting a couple of wells drilled and those wells are being permitted as we speak.

In Phase 1, because of the 20 acre downspacing, a sort of good news from our reserve add standpoint it has caused some additional water issues in localized areas and it has caused some restriction issues on our water-gathering system. So we had to go back in and we are expanding the size of those water lines to give more water to our disposal wells and Phase 1, in which we already have two disposal wells and we plan on getting another well drilled up in our 100 acres, So I guess what I’m trying to say is,at the end of the day, we will get out ahead of this water disposal issue and we expect those cost to come down.

Joe Allman - JPMorgan

Okay, alright that sounds like some of those are going to be more second half of '08?

Baird Whitehead

Yes.

Joe Allman - JPMorgan

Okay, sounds good. Alright, great helpful. Thank you.

Operator

Our next question is from the line of Richard Tullis with CapitalOne.

Richard Tullis - CapitalOne

Hey, good afternoon.

James Dearlove

Hey, Richard.

Baird Whitehead

Hey Richard.

Richard Tullis - CapitalOne

Lot of my questions have been answered already but just had a few more. In the Gulf Coast, what are you looking forward for production from their in 1Q, just your up numbers?

James Dearlove

I don't have that number. Hold on a second, would you? We'll have your next question, we are looking at it.

Richard Tullis - CapitalOne

Okay. What do you have planned for Gulf Coast in first half of this year and any high impact wells that’s one you just you mentioned in the opening remark?

James Dearlove

We have a well plan to -- it's actually a reentry going on in Stella right now, which could be a high impact well. It's up dip of a well that we drilled two or three years ago that has [ultimate on] of about 8 Bcf. So we consider it a low risk developing well via reentering and that's going on as we speak.

We will would probably get at least one well drilled in Creole. I won't call it high impactive or amplitude prospects typically in the two to three Bcf range, Its about $3.5 million doing complete. And we have a well to drill with a private company. I don't know when it's going to get spudded, maybe in the second half of the year. Well just got -- the upside about an 8 Bcf , we have a 25% interest in it.

It's an [amplitude[ AVO type prospect in a lower risk category. Probably, the biggest impact we had to deal will be, this offset a little flow again and yet to be determined when it will get spudded, but that would be the most material thing to us if it works.

Richard Tullis - CapitalOne

Okay. Looking at East Texas 20 acres spacing, how much of your acres you think is actually is viable at 20 acre spacing

James Dearlove

Well, I think most of that is in the phases 1 and 2 there are few dead spuds as you expect to find. And most of it has 20 acre potential in Phases 1 and 2 and the 100% acreage, there is no reason not to expect that based only in 20 acres space and will work in our acquisitions that when they.

Baird Whitehead

100% acreage up to the north, I still think at the end of the day about 50% of the acreage is going to be prospective, based on what we know right now. We are taking it slow and are gaining some information under our belt, getting some production information under our belt, but I think about half of that acreage will ultimately work also on a 20-acres spacing.

Richard Tullis - CapitalOne

Okay, that's all I have today. Thanks a bunch.

Frank Pici

Richard that answer on the order -- for the first quarter on the order I'll say about 15 million to 20 million day.

Richard Tullis - CapitalOne

15 to 20 okay, thanks.

Jim Dearlove

We don't budget successful exploratory wells either, that’s strictly based on PDT essentially.

Richard Tullis - CapitalOne

Okay, thanks a bunch.

Operator

(Operator Instructions). Our next question is from the line of Steve Berman with Pritchard Capital.

Steve Berman - Pritchard Capital

Hey good afternoon gentlemen. Woodford clarification Baird, and the question the 40,000 net acres that's combination Arkoma and. Anadarko?

Baird Whitehead

That's correct.

Steve Berman - Pritchard Capital

At least on the Arkoma wells that you are planning, do you have any economics there as far as well costs, how any frac stages etcetera anything you can share with us there?

Baird Whitehead

I really don't at this time, I'd say its going to fairly typical, what's going on in that area, being a new field and some lesser (inaudible) Chesapeake, but it would be probably very, very similar.

Steve Berman - Pritchard Capital

Okay. And then in the Fayetteville, I don't think you said how many net acres you have there?

Baird Whitehead

We've got roughly 14,000 net.

Steve Berman - Pritchard Capital

The wells you have drilled what counties are they in and then two year of your planning are sort of make or break ones where are those going to be drilled?

Baird Whitehead

They are all in Pope County, towards the eastern Pope County.

Steve Berman - Pritchard Capital

So, its all Pope pretty much.

Baird Whitehead

Yeah. It is.

Steve Berman - Pritchard Capital

Okay. That's all I had. Thank you.

Baird Whitehead

All right. You are welcome.

Operator

Thank you. Our next question is a follow up from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Thanks. I just want to touch on the Appalachian shale acreage and it sounds like the well that you are currently completing are compelling enough for you guys to look to acquire more acreage and think about development activities. Can you kind of give us some more color on what you are expecting there and the potential for you guys to do some JVs up in some Marcellus acreage. Could this be a fairly meaningful program for you by the second half of the year?

Baird Whitehead

Well, on the lower Huron acreage up in Mason County specifically, until we get some of these wells under test it's going to be hard to say exactly Scott. But we still think they are probably in 800 million Bcf type well. At least based on what we've seen so far there is no reason not to expect that. This is fairly close to what's (inaudible) is doing. We just happen to be on the other side of the river primarily.

So, the plan is, we've got roughly 10 mile line to get laid, to get this gas out. I would say that we would probably try to ramp up activity in the second half of the year in Mason County. We've got two wells budgeted that may go higher depending on the timing is applied, but in any case that's what we think at this time. In Marcellus to answer your question. Yeah, there are some sizeable tracks of acreage that are [HTP] by a number of companies who have been up in that country for ages.

We think that we bring something to the table we may have to trade to leverage our way in. So I think we can make some progress, yes. I don’t know with, I am thinking 50,000 acres plus. I think we want to have at least 50,000 acres to make any sense of it anyway. And we're looking at a two or three different areas within that play up with TAO written southwest TA up to North Central and Northeast TA.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Baird Whitehead

You are welcome.

Operator

Our final question this afternoon comes from Jeff Davis with Waterstone Capital.

Jeff Davis - Waterstone Capital

Good afternoon, just curious if you can update me on what the revolver balance is currently?

Jim Dearlove

Right now, our revolver balance is…

Frank Pici

Right now, our revolver balance is 134 million.

Jeff Davis - Waterstone Capital

Okay. And then second question just kind of curious if you can maybe help quantify any quantify what, if anything the recent move in coal prices means for PVA.

Jim Dearlove

No, we’ve got to Keith working on the pone and I know he has been chopping at the bell to get a word in warning wise, right. So, I let him answer that question, if he is not there, I will try.

Keith Horton

Okay. Jim, I’ll to, it’s the -- basically the coal prices this year about 90% of our -- lets say production was committed under contract. During the course of the year, about 50% of those contracts were rolled off. And so, we're beginning to see a significant affect during the later part of the year fourth quarter and into 2009, but predominantly 2009. We've seen some early affects with our marginal amount of spot coal movement in to that market. As well as some entity to stock contracts early this year. So, I don't have an exact dollar figure on that at this point in time but that's a magnitude of the coal contract situation.

Jeff Davis - Waterstone Capital

Thank you.

Keith Horton

You are welcome.

Operator

There are no further question at this time ladies and gentleman. I would now like to turn the floor back over to management for closing comment.

James Dearlove

Thank you. And again I thank you and appreciate the interest and the questions from those of you who participated today. We look forward to updating you again at the end of the second quarter and with that operator, I think we'll call it day.

Operator

Ladies and gentlemen this concludes today's conference. You may now disconnect your effective lines. Thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Penn Virginia Corp. Q4 2007 Earnings Call Transcript
This Transcript
All Transcripts