Ranger Oil Corp (ROCC) 2007 Q4 法說會逐字稿

Good evening, ladies and gentlemen and welcome to the Penn Virginia Corporation fourth quarter conference call. At this time, all participants are in listen-only mode. A brief question and answer session will follow the following 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.

Thank you, Rob, and welcome and good afternoon. I'm joined here today in Kingsport, Tennessee we have Keith Horton, who runs our Coal segment of PVR, as well as Forrest McNair, whose the Controller of the Corporation. In Houston we have Ron Page, who runs the Midstream piece of PVR, and here in Radnor with me is Baird Whitehead, who runs our Oil and Gas Business, Frank Pici, whose the CFO of PVA and PVR, Nancy Snyder, whose the General Counsel, of all of the above and Jim Dean, whose our Investor Relations person.

I would remind you that over the course of this call and several of us will be speaking, we're are libel 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, it has 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 going to bounce around a little bit more than normal, but I'll just try to keep it as orderly as I can.

As you can see, from the release, Penn Virginia Corporation enjoyed a, I think a very good year from both a production and a reserve growth standpoint and frankly from a cash standpoint as well I'd say. In fact production for the year was just under 41 Bcf equivalent, a 30% increase and proved 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 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 it comes from. That expense results mainly from changes in the valuation of unrealized derivative positions. Most of that expense has been noncash result of accounting for mark-to-market variances that carry over from PVR, our MLT. And Frank will address the hedge program as well as the derivative issues here in a few minutes.

We try to give you a different picture of net income using something that we call adjusted net income, which excludes the effects of those noncash charges. That number was just under $70 million for the year or about 15% over 2006. For the quarter, the fourth quarter, it sort of is a mirror of the year. Production was up 25%, 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 for PVA, the entire consolidated operating income, was $193 million or 13% over 2006 and the release details for you the more important factors that affected operating income and operating cash flow both positively and negatively. And obviously we'll spend some time addressing cost issues et cetera here in a minute.

Basically however, the higher oil and gas production and the higher processing margins at PVR Midstream partially offset by our higher expenses across the Company and a slight lowering of operating income from PVRs Coal and Natural Resource segment determined what our operating income was for this year. And as I said it was up about 13% over last year. Net income for the fourth quarter was heavily influenced by this derivative expense. Again these are non -- basically noncash changes in the valuation of unrealized derivative positions, and again Frank will speak to that.

What I'm going to do now is depart from the 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 as an MLP that we formed seven years ago. It's now-- it's general partner is now owned by something called Penn Virginia GMP Holdings an MLP that we formed last year and then end-- right at the end of 2006 in which we own 82% of. It in turn owns the general partner and the incentive distribution rights of 42% of PVR. So what happens at PVR flows 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 websites that contain the releases for both PVR and PVG. And they're easy to get to and easy to navigate through.

I'm not going to spend a lot of time. I'll going to give you a little more detail on the paragraph that's in the release and that's to say this. The most important thing I think in an MLP is distributable cash flow and for PVR, and I say that, that passes then through PVG and on up to us, the cash available to distribute to the limited partners last year was up 20% to $120 million. That was a new record for PVR. It also set a record for operating income which was up 14% to 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, PVR's adjusting net income was much higher than the preceding year, up to $89 million to $67.7 million. But net income was a little bit down because of those -- the issue with those derivatives. Likewise the quarter, again it was a mirror image of the year, record levels of distributable cash flow and operating income, high levels of adjusted net income but lower net income.

And then finally on that subject, just a little bit of color. PVR Midstream had a very good quarter and built 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 it's existing facilities in the Texas panhandle. And perhaps more importantly the PVA is also very close and we would expect it to -- the plant to be available to be operated in the end of the first quarter and hooked up sometime a little bit after that. It's -- at any rate, 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 joint -- I guess 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 then is with regards to PVG, they make distributions to us, they're going to make a distribution on the 19th of this month of $0.32 a unit, annualized. That's $1.28 a unit. What all that means is that it is about 8% over where it was for the third quarter of '07 and about 33% over last year, translating that into money, it would represent, if we held these distributions flat, $41 million of pretax cash coming to PVA and over the course of the year, our -- the value of the units that PVA holds in PVG has increased by about $300 million to just under-- to just over $800 million. So that -- with that, I'm just trying to, dispose is the wrong word, but explain and cover the MLPs.

Now at the heart of the matter here is Oil and Gas. And 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 Bs, roughly two thirds of that increase came through the drill bit. We did have a successful acquisition program but most of that growth 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 additionals 445%. And as I said, the rest of that result was a result of 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, the various expense categories in the Oil and Gas segment and as you might expect, a 30% increase in production reached a higher revenue, higher operating income but also causes expenses to increase. I won't read each and every one of these to you but we're quite happy to talk about them as things unfold.

With that, what I think I'll do is I'll turn over to Baird, a more detailed discussion of Oil and Gas ops. Or was I going to, Frank we were going to start with you and numbers I guess? 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.

Okay, thanks Jim. And then we'll go to Baird after that.

Yes, yes.

Just a couple of things to touch on in the release. The, the-- I guess one would be the derivatives since that's obviously a very volatile number in our income statement these days. Since we switched over to mark-to-market accounting sometime 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 opened positions. And the fourth quarter caused some fairly noticeable volatility. As Jim mentioned, most of that came through the Midstream segment that we report, the PVR Midstream segment that has to be consolidated in and that was effectively most if not all of the derivative expense that we reported for the quarter. That's really result of the run up in oil prices and the effect that that run up had, excuse me, on the opened positions that PVR Midstream has taken on to mitigate it's processing margin risk.

On the Oil and Gas side, we actually had some benefit. And the way-- maybe a way to express that to you and by the way what we do of course, we give that you adjusted net income number now that takes out the mark-to-market impact and puts in just only the cash impact of the hedging and we believe puts net income on perhaps a little more understandable quarter-to-quarter, year-to-year type of comparison. But in 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 a benefit, excuse me, 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 out for the cash payments on the hedges, that goes to 20-- a little over $23 million. So it's about a $7 million-- $7.6 million reduction.

That if you look at on a processing margin per Mcf of inlet volume basis, that takes the margin down from 181 in Mcf to 136 in Mcf. But when you compare that to the prior year that 136 adjusted on the same basis would have only 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 effect on the Midstream margin was $1.13, net of hedging payments, versus $0.82 from 2006. So again, very impressive increases year-over-year. So the point of all that being, 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.

When I switch gears a little bit and look at the Oil and Gas segment. Maybe the best way to express that is the impact that our hedging activity had on our price realizations and for the quarter, and natural gas by the way is pretty much all we hedge. I don't believe -- we do not 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 we have was to increase our effective realized price by about $0.37 in Mcf equivalent. And then on the -- for the full year it was about $0.38. So it was an impressive increase in our realized price. Again, we actually received cash on those gas hedging positions we had. So when I look at going into 2008, we've got -- we do have on both segments of the businesses, we've got hedging positions 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 the Oil and Gas side, I think we're running roughly 35% to 40% hedged on that side as well. And actually on the Oil and Gas side, we've got some volume hedged into '09 as well. Not a whole lot but we're increasing -- we're looking at increasing positions as we go through time here so that number will go up over time. Jim, do you want me to speak to guidance now or--?

No why don't we let -- we'll end with guidance and Baird if would you just walk us through operations. I'd remind you we that had an operations release yesterday as well and I suspect Baird you'll be talking from that as much as anything.

Rather than focusing on what we do in 2007, I think probably more important is to speak what we plan on doing in each one of our played 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. Today we drilled two horizontal wells in late '06, early '07. Those two wells continue to considerably outperform a vertical counterpart. 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. And in Baxterville we've made 4.5 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 are in Baxterville. We got at 3500 feet laterally in both of them. Utilizing an H&P flex rig. We have not completed those. But we will start completion on both of those wells as soon to be and will perform anywhere from a 7 to 8 stage frack job on both of those wells. The plan is to 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 rig also drilling out in front of it. But in any case we're extremely encouraged with the results 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 Appalachia 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 expectations. With rates of returns in excess of 50% after tax. On the down side, what has our activity limited as we continue to have some problems of getting drilling permits because of an active coal industry, but we also continue to talk with some of these coal companies to see if we can come up with a global agreement to at least minimize these interruptions and get more of these drilling permits in inventory so we can continue to add some rigs.

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

On the Devonian Shale, which is another one of these hot topics in the business any more. Speaking with Mason County first, we have drilled our two Mason County wells, one of which had 2600 feet laterally, the other one of which had about 1600 feet. One had been completed. It is currently cleaning up after fracs, since it was just fraced last week. It's too early to report any at this time but in any case it appears be encouraging. The second well we should frack in the next day or two. We are encouraged enough that we are starting to pick up right away to get this gas act not only of course from these two wells but more importantly a development drilling 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 8500-acre 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 the Marcellus and the Lower Huron. We had some operational completion problems in the Marcellus. That well tested, in the Marcellus and the Lower Huron, admittedly there is 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, is there are some titanium zones up a hold that we will go ahead and complete in the vertical well to get some idea of the potential of the vertical -- or get some idea of the potential of the titanium zones. This is a 13,000-acre lease plus or minus that's undeveloped so there could be a lot of upside just on the titanium 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 [stighter] rig because of the depth. But the plan is to try to get that thing started 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, in the late '70s. So in any case we got to try it. We think there's sufficient gas in place, so something hopefully we can report toward the end of the year.

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

In the Cotton Valley, our wells continue to meet our expectations. We continue to drill with 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 [dye] spacing is working and is working well. Last year we had about 90 PUD in the Cotton Valley because of that 20-acre [dye] spacing program and it results in a success to date that PUD inventory has gone up to almost 280 in the Cotton Valley. So in any case, the 20-acre program is working very well. We, as I said earlier, we are exploiting opportunities on the two acquisitions. The acquisition and especially that is adjacent to Phase II, were our better Cotton Valley wells are in general, we're very pleased with the results to date 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're trying to get a vertical well drilled down through it just for some pilot hole type information before we spread to a horizontal well but again we're as enthusiastic about that as ever. To remind you from a resource standpoint, the Lower Bossier has about 150 Bcf about for every 640 acres and we also think there's potential in the Upper Bossier, which we think is about another 50 Bcf on top of that. So to think about Bossier in general, it is a shale, it's higher pressure than the Cotton Valley. But even if you take 20% of that resource per section, we're talking about 40 Bcf growth. 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 ourself. That well was turned in line just after the first of the 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 but that's net to (inaudible) Virginia, after royalty, you can do the math, we think you could have potentially about 120 Bcf of opportunities for us in reserve add to over the coming two or three years. The plan is to drill six net of these wells in 2008.

On the Shale front, on the Woodford, we've not talked a lot about that. We've got north of 40,000 net acres between Pittsburgh and Macintosh Counties in the Arkoma. Admittedly this is on northern end of the Fayetteville but the stuff in Pittsburgh 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 prefer not to disclose where that is specifically at this time for competitive reasons but it is our plan to drill around four gross wells this year, probably around one to two net depending on working interest, two of which will be in Arkoma, two of which will be in the Anadarko Basin.

In Fayetteville, inception to date we have drilled nine gross, almost four net wells. We have operated four of those wells. We have seen IPs across the nine wells of anywhere from 200 Mcf a day to 1.5 million a day. The last two well that we drilled and fracted are performing better than what we had seen on some of the earlier wells we drilled or participated in. We've got a significant amount of load water yet to recover, but in any case, where some of (inaudible) 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 an approximate 35% partner. We will drill a couple horizontal Bakken wells in the first half of the year. To get some idea of the potential of our acreage, after which we will either ramp up 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've declined, continue to make about-- two Cotton Land well continue to make about 25 million a day gross. We've 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 aptitude prospects to drill in our Creole field which we have drilled under the last three or four years. There's probably a better chance than not that we will also get a well spudded as an offset to the [La Floyd] well that has been up in the air 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 be determined but we think it will 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 (inaudible) drilled and turned in line, I think it was in September of this past year, with an initial rate of about 40 million a day and about 700 barrels of oil a day. And we have the right to participate 25% in this direct offset. So that could be material to us also going forward.

But in any case, you can see we've got a number of things teed up. We have a backbone of good development opportunities between the Cotton Valley and the Shale and the horizontal CBM and the things we're doing in the Mid-Continent and we're encouraged with the opportunities we have on the table.

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 somebody -- everybody on this call at least a pull back the curtain a little bit so they can see what we're up too. And Frank I think you wanted to then talk about guidance?

Yes. Just a little bit, thanks. And just to kind of dovetail with 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, we've got the production guidance there and we do expect there to be a noticeable increase in production and I think we-- this is unchanged from what we had issued sometime ago when we announced our capital program for '08 on the production side. So there's really, there's really no change there. The-- there are -- there have been a couple of changes with respect to the operating expense guidance and the DD&A guidance. With respect to operating expenses, you probably saw in the release that we had some heavier expenses in the fourth quarter relating primarily to water -- some water disposal costs largely in East Texas and then some down home 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 bumped up our guidance a little bit on the cash operating expense side, it's now ranging in the 210 to 230 range. That'll vary based largely on how, how we get the water disposal issue in East Texas resolved and that will -- we expect that to happen in the first -- 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 at -- 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 our MLP. That was effectively not burdened with DD&A. So that was-- that used to help our rate, doesn't really help our rate going forward. But factoring those kinds of things into the rate, we thought it was prudent also to increase our guidance on the DD&A side somewhat and it's now ranging in the 250 to 265 area, so you'll see that.

With the capital expenditures we've kept that guidance as we showed you when we announced our '08 budget. We did I think mention if we haven't all mentioned here, that if you take out -- if you take the '08 CapEx of $520 million and you back out the acquisitions, that leaves us with 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 the -- some increase in production there, largely driven by the -- a switch deal in Illinois basin on the full side. That will have the implication of reducing the overall average royalty per ton from what we-- what PVR realized in '07, that's largely mix driven again. Depreciation on that segment will go up some again as a factor of having more production from higher cost basis areas more recent acquisitions. On the Midstream side, we're reflecting the increase in throughput volumes as a result of the new plants Jim talked about in East Texas which will also benefit our East Texas Oil and Gas operation. And there's a new plant in PVR Midstream's Beaver/Perryton complex in the panhandle of Texas as well, that'll both serve to increase volumes quite a bit year-over-year. Those will have corresponding increases, cost corresponding increases in both operating expense and DD&A. We've reflected that in the guidance.

I guess the only other thing I'd like to hit on 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 some things related to finishing up our new systems conversion that we've got completed now. When you look at the guidance for '08, you'll see that the expected G&A expenses sort of normalizes back down if you will as a lot of the one time things we had in '07, especially for the new system, tends to get through this-- 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 expense -- our interest expense as well. So with that in mind, Jim, I think I've covered the key points.

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

Thank you gentlemen. (OPERATOR INSTRUCTIONS) Our first question today comes from the line of Scott Hanold with RBC Capital markets.

Thanks, good afternoon.

Hi, Scott.

Hey. 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?

Are you talking about the offset in [La Floyd], Scott?

No, I'm sorry I guess the Gulf Coast-- yes.

I'm 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's made [kune] but it's made 3 Bcf plus and it watered out almost overnight. We have pinpointed the problem to some extraneous water. We have a work over rig back on this thing as we speak right now to squeeze it which means to get this water squeezed off and re-perforate in the zone and we think we'll get it back. I can't guarantee you we're going to get back off 4 million a day, but it appears not to be a depletion associated with the reservoir itself. It just appears to be some adjacent water that just got drawn into the well because some of primary bonding on the cement problems.

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

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.

Okay and can I ask what your current production rate is here?

It's around 120 million a day would be a good number right now.

Okay around 120, so that would include that Granite Wash well, is that right?

That's correct.

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

Well, to some extent, to a large extent, not to some extent, it's going to be dependent upon the startup of our plant. To remind you, the plant in East Texas will be recovering, I can't remember what it is. But it's about 1,000 barrels a day of liquid. So that adds 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 it's to some extent it's dependent upon the startup. But it'll be probably in the mid 120s if I had to guess, early second quarter.

Okay. That's helpful. And in East Texas, could you talk about the pud wells you booked? I guess you said there's 280 pud wells that were booked. How many of those are 20-acre spaced wells?

Almost all of those now are 20 acres. Because we had all of our wells last year booked on 40-acre spacing but 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 wells-- 20-acre wells in between. To remind you, we still have a large inventory of probs and possibles out there. And we'll that 3P report done here probably in the next two to three weeks, but any case there's still a lot of probs and possibles in inventory.

Okay. Okay and then can you say what you-- how big the PUDS you booked were? Are they like 1.3 B type PUDS out there?

I-- we based it more on direct offset this year because of performance in the area. But I don't have that number in front of me but I'd say it's about 1.2 average.

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

Let me just-- Scott, let me just say one other thing. It's actually higher than that. One thing I forgot to tell you, is we booked liquids in our PUDS now and liquids add about 180 million equivalent gross per well. So it probably is closer to 1.4 would be the average well on the PUD side.

Okay. Okay with the liquids. Okay good and just one more question on East Texas, 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 the six rigs in the fourth quarter. Could you find of speak to what your plans are as far as if you continue that rate, would you plan on increasing activity or would you potentially slow it done during the year?

Well I think the economic conditions will dictate at that time. One thing we find is continued improvements in drilling efficiencies and we-- and I think we've talked about that in the past, which once took 15 days or 20 days to drill a spud [TD], now we're down into single-digits. In fact we've gotten some wells 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 some things -- one thing that will slow it down is our Lower Bossier horizontal well. I mean that'll. that'll probably be a 30 to 45 day well so that will slow down the Cotton Valley for a little bit and we still have planned a Cotton Valley horizontal well to drill sometime this year. So that will slow it down a little bit. But I could see us maybe drilling a few more than 140 net wells in 2008.

Okay. Thank you.

Hey Scott, one other point I wanted to make. This is Frank. I normally don't break in like this. But I had meant to make this point when I talked about the guidance. But when I talked about expenses for East Texas and I mentioned that we don't expect them to go down much, part of that is having this arrangement for the plant -- the processing cost at the plant. Well that's only one side of the equation of course. We'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're going to get a higher margin on that production than we were getting currently because we don't get that pick up now on that NGL. So I just want to make the point that even though our expenses look like they're going up there's going to be a higher margin associated with that production. So that's a helpful economic thing to understand.

Okay thanks. That's good. Thank you.

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

Hi, good afternoon, everybody.

Hi, Joe.

Hey Baird on that one Granite Wash horizontal. I'm not sure if you talked about the cost. Could you talk about the cost to drill and complete that well and what do you think the costs are going forward?

Well our well is the expensive because we had a couple of side tracks. But we think our routine basis based on when our partners is doing is $7 million to $7.5 million gross. It's probably a good number, if not a little bit less than that.

Great. And then -- okay and then at Baxterville, in your operations update you said you had two dry holes in the fourth quarter. Was that typical kind of stuff or is there anything unusual in that?

We -- in Baxterville, occasionally we get caught up in some faults and the zone -- the chalk itself is only 30, 40 feet thick and sometimes you get caught up in a fault and it's faulted out. And we find it's actually cheaper to gather the subsurface information based on the drilling and just go ahead and drill a new well rather than trying to do via side track. But it occasionally happens, not very often but occasionally.

Okay got you. And then that joint venture you have with Phoenix Gas, what's the target for that joint venture? What formation?

It's multiple Pocahontas steam poles.

Okay.

There's five or six or seven and I cannot remember all of the names. But there's multiple seams. These are vertical wells by the way, they're not horizontal. And they may frac anywhere from five to ten zones, five to ten seams.

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

Well, in East Texas we're seeing it come down. We just negotiated a new stimulation agreement. We brought our costs down maybe -- I think it was almost 10%. We're seeing cementing costs come down somewhat. We're 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 type of wells we drill horizontally and those being under longer term contracts with CDF and their rigs those costs stay fairly flat. Mississippi since we've gone to the horizontal concept in using a flex rig of H&Ps on a per day basis we've gone from drilling those wells from turnkey on a vertical program with a private contract to now a day work contract horizontally. So it's pretty hard to say going forward those costs are going to be, but we're drilling on a well-to-well basis so I would assume depending on demand they may go up, they may come done.

In the Mid-Con, we really do not think -- I don't think they changed a lot based on what I've seen. Again, we are unique in what we do there. Generally horizontal harsh warm cold wells and now this 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, and deeper land rigs appear to be coming down somewhat in South Louisiana so some of the wells we may drill there I think will be a little bit cheaper.

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

Well let me approach it by category. On the subsurface maintenance that Frank talked about. That kind of stuff typically is discretionary. We do things to try to enhance production with expense work overs during restimulations, those kind of things, you see a-- hopefully a production benefit by that kind of stuff. But you can sort of turn it on, turn it off as you want to. We're going to continue to do those kind of things if we have the opportunities in front of it. On the -- on this [Fernette] Well, for instance, South Texas well those are one-- this is an expense work over. We want to do it, have to do it just because of the sheer amount of remaining reserves justified. But there are some things that will go away like maybe in our chalk on some of the subsurface maintenance we do there. Some of the subsurface maintenance we may do in East Texas is volatile because we operate on gas lift there and sometimes you've got to change that gas lift valves and that takes the rig and so it's volatile.

And compression expenses, it went up this year primarily -- or this last quarter because of the compression we said in our Cotton Land wells which is expensive compression but again it clearly helps the production rate. To some extent also in East Texas on the SWDs, which was a fairly substantial expense in the fourth quarter, we will see those costs come down. We have things in motion to drill or recomplete two disposal wells in Phase II. We already have a water gathering system in place there. It's just a matter of getting a couple of wells drilled and those wells are being permitted as we speak.

In Phase I, because of the 20-acre [dye] spacing, it's sort of a good news from a reserve standpoint. It caused some additional water issues in localized areas and it's caused some restriction issues on our water gathering system, so we had to go back in and are expanding the size of those water lines to get more water to our disposal wells in Phase I of 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, and we expect those costs to come down.

Okay, all right. And it sounds like some of those are going to be more second half of '08?

Yes.

Okay sounds good. All right. Very helpful. Thank you.

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

Hey, good afternoon.

Hello, Richard.

A lot of my questions have been answered already. But just had a few more. In the Gulf Coast, what are you looking for for production from there in 1Q, just rough numbers?

I don't have that number.

Hang on a minute, Richard.

Hold on a second, Richard. Well ask your next question and we'll come back.

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

We have a well-planned to -- it's actually a recentre going on at [Stellar] 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 an ultimate on it of about 8 Bcf. So we consider it a low risk development via re-entry and that's going on as we speak. We will-- we would probably get at least one well drilled in Creole. I wouldn't call it high-impactives or amplitude prospects. They're typically into 2 to 3 Bcf range at about $3.5 million drilled and complete. We have a well to drill with a private company. I don't know when it's going to get started. Maybe the second half of the year type well that's got the upside of about an 8 Bcf. We'll have a 25% interest in it. It's an amplitude ABO type prospect in the lower risk category. Probably the biggest impact we have to do will be this offset to [La Floyd] and yet to be determined when it will get spudded, but that would be the most material thing to us if it works.

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

Well, I'd say most of it in Phases I and II. There are a few dead spots as you expect to find. And most of it has 20-acre potential in Phases I and II. On the 100% acreage, there's no reason not to expect that based on what we know 20-acre spacing will not work. It will work in our acquisitions that we made.

Okay.

100% acreage up to the north, I still think at end of the day about 50% of the acreage is going to be prospective it--based on what we know right now. We're taking it slow. Are getting 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 20-acre spacing.

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

Richard. That answer, on the order-- for the first quarter on the order, I would say about 15 to 20 million a day.

15 to 20. Okay. Thanks.

We don't budget successful exploratory wells either. That's strictly based on a PDT essentially.

Okay. Thanks a bunch.

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

Good afternoon, gentlemen. Words for clarification [beared] in a question. The 40,000 net acres, that's carbonation or (inaudible) in Anadarko?

That's correct.

And the-- at least on the Arkoma wells that you're planning, do you have any economics there as far well costs, how many frac stages, et cetera, anything you can share with us there?

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

Okay and then the-- in the Fayetteville I don't think you said how many net acres you had there?

We've got roughly 14,000 net.

And these next -- the wells you have drilled, what counties are they in and the two your planning, sort of make or break ones, where are those going to be drilled?

They're all in Polk County, sort of Eastern Polk County.

So it's all Polk, pretty much?

Yes it is.

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

Your welcome.

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

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

Well on the Lower Huron acreage, on the first-- up in Mason County, specifically. Until we get some of the wells under test it's going to be hard to say exactly, Scott, but we still think they'll probably in the 800 million to Bcf type well, this is based on what we've seen to far there's no reason not to expect that. This is fairly close to what's [Cabat's] doing. We just happen to be on the on the other side of the river, primarily. So the plan is try-- we've got roughly a 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 already got -- we've got two wells budgeted that may go higher depending on the timing of the pipeline. But in any case that's what we think at this time.

And the Marcellus, to answer your question, yes, I mean there are some sizable tracts of acreage that are HVP by a number of companies that have been up in that country for ages, that we think that we bring something to the table because of what we may have to trade to leverage our way in. So I think we can make some progress there, yes. And I don't know with-- I'm thinking 50,000 acres plus. I think we would want to have at least 50,000-acres to make any sense out of it anyway. And we're looking at two or three different areas within that play up in PA all the way from Southwest PA up to Northcentral, Northeast PA.

Okay. Thank you.

You're welcome.

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

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

Right now our revolver balance is -- right now our revolver balance is $134 million.

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

We've got Keith Horton on the phone and I know he's been chomping at the bit to get a word in edgewise, so I'll let him answer that question. If he's not there, I'll try.

Okay, Jim, I'll take it. The-- basically the coal prices this year are about 90% of our lessee production was committed under contract. During the course of the year, about 50% of those contracts were roll off. And so we're beginning to see a significant effect during the latter part of the year, fourth quarter and into 2009 but predominantly 2009. We've seen some early affects with a marginal amount of spot coal moving into that market as well as some entities who signed contracts early this year. So I do not have an exact dollar figure on that at this point in time but that's the magnitude of the coal contract situation.

Thank you.

You're welcome.

There are no further questions at this time, ladies and gentlemen. I would now like to turn the floor back over to Management for closing comments.

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 a day.

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