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Executives

A. James Dearlove – President and Chief Executive Officer

H. Baird Whitehead - Executive VP & Pres of Penn Virginia Oil & Gas Corp.

Frank A. Pici - Chief Financial Officer

Analysts

Scott Hanold – RBC Capital Markets

Joseph Allman – JP Morgan

Sven Del Pozzo - C. K. Cooper & Co.

Irene Haas – Canaccord Adams

Richard Tullis – Capital One Southcoast

Biju Perincheril – Jefferies

David Snow – Energy Equities Inc.

Penn Virginia Corporation (PVA) Q3 2008 Earnings Call November 6, 2008 3:00 PM ET

Operator

Welcome to the Penn Virginia Corporation’s third quarter financial results conference call. (Operator Instruction) It is now my pleasure to introduce your host, Mr. Jim Dearlove, President and CEO.

A. James Dearlove

Good afternoon. I am joined on this call by a number of people and I’m just going clockwise here. Baird Whitehead who runs our oil and gas company, Frank Pici who is our CFO, Nancy Snyder who is our Chief Administer Officer. They’re with me here in Radnor. Forrest McNair our controller and Keith Horton who runs our coal segment is in Kingsport, Tennessee.

What I will do is I normally do is to follow the highlights of the press release. I would remind you than in the press release we tell you there are forward-looking statements and we will probably make some of those today and caution you that they are just that. And also I would caution you that I will not read every word nor every number that is in this report so I would encourage you to read this report. I am going to make a very short reference to both PVR and PVG, the MLPs with which we are associated. Their reports are on our website and their conference was recorded about two hours ago and if not available right now will be available shortly.

So with that let me just walk through the release of yesterday, November 5, 2008 for PVA.

We had a very good quarter in terms of production, a record level of production, 11.7 Bcfe or about 127 million a day (MMcfe). This is a year-over-year third quarter to third quarter growth rate of 5% and it’s about 2% higher than it was in the second quarter of 2008.

Operating income was $122.0 million. That happened to also be a record, well above the roughly $52.0 million we had in the third quarter of 2007. And most of that increase, and we’re talking about PVA now, not just the oil and gas portion of it, most of that increase was due to the oil and gas segment and an awful lot of that increase was due to an increase in prices. Reminding you now that we’re talking about the third quarter, not the fourth quarter where we are now.

And in that third quarter, especially early in the quarter, we had very high gas and oil prices as well as natural gas liquids prices. We also had an increase in production, as I just mentioned.

We also experienced an increase in the operating income from our MLP affiliates. The coal company was up about 48% year-over-year, and actually the mid-stream segment was down slightly due to the Hurricane Ike, down about 2%, but overall PVR was up. So those both contributed to the operating income that we reported at the PVA level.

Operating cash flow, a non-GAAP measure, was $97.5 million in the quarter compared to about $79.0 million in the third quarter of last year, most of that due to the changes in operating income offset by the cash to settle some derivatives.

Adjusted net income, also a non-GAAP measure, but the reason we use it is it excludes the non-cash changes in derivatives fair value, was about $46.0 million as compared to about $18.0 million or $19.0 million in the third quarter of 2007. And again, the same reasons that applied in the operating cash flow line.

Net income, which is a measure, and an awful lot of people look at EPS. I understand it, I don’t know how critical that measure truly is, but nonetheless, for us, we had a very good quarter, it was $123.7 million at net income compared to only $17.0 million in the third quarter of 2007, and an awful lot of it due to a large increase in derivative income, that’s a non-cash change in the value of the unrealized derivative positions we had. But it was also due to the higher operating net income that I just spoke about, offset by some increase in taxes and minority interest.

The oil and gas segment I am going to let Baird do most of the talking about. Let me just sort of lead with some of the things that are in this release. We mentioned our quarterly production growth year-over-year and quarter-over-quarter, capex was $236.0 million of which $152.0 million was on drilling and completion. That’s a lower percentage than we normally would have. Usually most of our capex is drilling and completing but you will notice here some lease acquisition costs, in particular, of about $70.0 million, which is sort of an unusual event but we were bulking up in the Haynesville primarily in the third quarter.

Guidance for the full year, which Frank Pici will be talking to later on, but is 46.5 Bcfe to 47.5 Bcfe and if we hit the midpoint of that guidance we would end the year about 15% production increased over what we were in 2007. We reaffirmed which at least tells you our full-year cash operating expense guidance as well as our capex guidance.

And with that I will ask Baird to take us through the regions.

H. Baird Whitehead

We’re going to go through each one of the areas and let you know what’s going on, and of course spend a lot of time on the Lower Bossier, so I will begin with East Texas.

Right now, as was in our press release, we have four rigs going Lower Bossier horizontal shale wells. We have three rigs current drilling Cotton Valley wells. Two of those three rigs will be released here probably in the next week or two after they finish up on the wells they’re on and the third Cotton Valley rig we are actually moving over to start drilling Bossier well. So by the end of the year, mid- to late-November, we are going to have five rigs drilling Lower Bossier wells with no future plans, at least in the short term, to be drilling any Cotton Valley wells.

To go through the five wells we have drilled to date, the Bossier wells we have drilled to date: the Fogle #5, which is the discovery well. It is still producing about 2.0 MMcfe and 10 to 15 barrels of oil a day. We reported in the press release ultimate reserves of this well of anywhere from 6.0 Bcfe to 8.0 Bcfe. At least based on how this thing is acting, I think there is a strong case to be made that it could be as high as 10.0 Bcfe because of the production profile this well has.

It has produced 460.0 MMcfe in the past 143 days for 3.2 MMcfe a day, which I realize is less than what some of the other wells have been reported at in the play but this well is acting a lot different. I’m not saying every well we drill is going to act the same as a Fogle well.

When we got into this play we expected hyperbolic decline as any of these resource plays produce like, but we expected a, refer to as a N factor to deem on the lower side, which is the exponent that describes the shape of the curve. Well we’re actually seeing a much higher N fact which means you see a higher initial decline rate but the well actually flattens out in a shorter period of time. In fact, that’s what we’re seeing in this Fogle one. I’ve seen this happen before in some of these other resource plays. The Devoney Shale typically has some very high N factors. But in any case, the current instantaneous decline rate of this well right now is about 30% and based on how this thing is flattening out we think that it is very easy to forecast it could be north of an ADCF kind of well.

Again, I don’t know if this is going to be the typical type curve for a Haynesville well. I am sure you are going to have some different type curves for different areas of the play. You are going to have some sweet spots in this play in general. They are going to have different type curves, but in general right now this is how the Fogle well is acting.

The Gibson well, which was about a 2 mile offset to the Fogle, we did announced in our press release it was making 3.5 MMcfe a day, it was flowing like 2,800 pounds. We treated it with a little over 1 million pounds of sand over seven stages. And we have it cut back.

We have intentionally, on the next couple of wells, we have decided to bring these wells on at much more restricted rates. The reason being is we didn’t see a lot of water recovery on the Fogle well. I can’t exactly explain that but the last couple of wells we are bringing back at restricted rates, that being the Gibson and the McKenzie well are cleaning up a lot better and we are seeing fluid recoveries much higher at this point in time of their productive life.

The McKenzie well, which is a 20 mile offset to the Fogle, which is in the northernmost part of our acreage, of course is a key well. It has been turned in line, it is still making 700 to 800 barrels a day of frac fluids. We have only recovered about 10% of our frac fluids but it is bringing back fluid at very good rates. It is probably not appropriate for me to say what it is producing at this time since it has only been in line now for a few weeks, but it is something we will talk more about in the fourth quarter.

The Brown well, which was also a 2 mile offset, in a different direction, of course, than the Fogle well, we had a mechanical problem when we were fracking that well, the casing parted. We have made some progress in getting the casing put back together so we think we will get that well back on and get it flowing back. I doubt if we are going to complete the last two stages of the frac job. The plan right now is to get this thing put back together and start flowing and cleaning it up and then come back and treat the next two zones at some point in time.

The Fogle #6 has been drilled and we are currently completing that well.

So that’s everything I know as far as the five wells we have drilled today. As I said, we have four we are currently drilling in that play. We’re drilling laterally, as we speak, in the Penny Jones 8H, which is also up in our 100% acreage, up to the north. The Gail [fur] 11h which is a 100% well in the eastern part of our acreage. The Steig 1h which is also up in our 100% acreage up to the north. And the Fogle 7h, which of course, by name, is also a development well down in the overall Fogle area.

It is our tentative plan that we’re going to keep five rigs drilling, both on our 100% acreage and our GMX acreage in the Haynesville going forward.

We have made a few operational changes on Haynesville because of the casing parts that we had. In the Brown well we’ve started running a 4.5 casing all the way back to the surface which can stand much higher treating pressures. We are actually landing the lateral now in the upper portion of the Haynesville whereas before we were landing it in the bottom third in the organic part of the Haynesville. The reason we’re doing that is because the upper part is more of a reservoir-type rock, it having more of a siliceous content.

We are improving the type of bits we’re using to drill these laterals and have increased penetration rates as a result. And in going forward I think you are going to see us start increasing the number of stages we do and probably backing off on the treatment size per stage. But we think it is important to go ahead and place these treatments along the lateral at much shorter intervals.

Next year, and I talked about this before, the Upper Bossier, we think that is a valid stand-alone play. It is right beneath the base of the Cotton Valley. We have some immediate pressure increases as we drill through this stuff and have some good gas shows, so for that reason we also think it’s a reservoir that merits horizontal drilling and you will see us drill a well in that stuff some time by next year.

Switching gears to Mississippi, we continue to be very pleased with the results in our horizontal chalk program. We pointed out in our press release the average for the 90 days is about 800 MMcfe a day. The average for the five wells that have produced longer than 180 days, the average for those five wells is about 650 MMcfe a day at that point in time. So we continue to be very impressed with the results of these wells, we still think these wells are close to 2.0 Bcfe kind of wells.

Possibly they will make anywhere from 4.5 to 5 times that as a vertical well. We have just moved in the second rig into Gwinville so now for the rest of the year we are going to have two rigs drilling in that play. We made a lot of improvements here recently in drilling time. The initial wells, of which we have drilled 12 to date, were taking us about 30 days to drill. The last two wells we drilled respectively in 18 and 17 days. And the intent, going forward, is to keep two rigs drilling in this play, tentatively, for 2009.

In Mid-Continent, we continue to grow that area. Originally, I will remind you, it was primarily a horizontal Hartshorne CBM play in the Arkoma basin. Because of horizontal drilling in our Granite Wash play in Washita County, Oklahoma, we are starting to see our production increase more significantly because of the frac of wells.

We did report in the press release, we drilled four wells in the third quarter. Two of those wells had rates of 10.9 MMcfe and 10.5 MMcfe accordingly. The third well, which was just turned in line at the time, was making about 17.2 MMcfe a day, and the fourth well, which we had no production information as of a week ago, that well is actually making about 9.0 MMcfe a day and about 820 barrels of oil a day per 14.0 MMcfe a day equivalent. And I think, if I’m not mistaken, that is the best well that’s been drilled in that play to date, with Chesapeake.

We think, going forward, we are going to be able to keep two to four rigs drilling in that play. The economics of this play are very solid to a large extent because of the liquid content.

The other play type in the Mid-Con, where we have recently become pretty busy, admittedly, by outside-operated wells, is at Woodford Shale. We drilled two in the second quarter, we drilled three more in the third quarter. Those three wells we drilled had 3.6 MMcfe, 4.6 MMcfe, and 2.7 MMcfe a day respectively in the first 30 day rates. We have four rigs currently drilling right now that are all outside-operated by Intierra. And Petra Quest, with working interest of anywhere from 5% to 42%.

Going forward again, I am not as clear as our activity level was going to be in this play, but I think in the short term we should be able to keep between ourselves, Intierra and Petra Quest anywhere from two to three rigs.

And the last thing to make on, we will be testing our own Woodword idea in the Anadarko Basin. We have a rig we will be moving in here in a few weeks. We have put together about 40,000 net acres in that play area so we are going to be able to test our own idea.

Going to the Gulf Coast, we did announce a couple of good wells that we had drilled, one of which was the Cotton Land #5 in which we had about a 40% working interest in at wells making 15.0 MMcfe a day and 50 barrels of oil a day. We also backed in with a 25% reversionary interest and the prospect that we actually internally generated that is a huge well. That well has made about 17.0 Bcfe in a little over a year, still making about 3.5 MMcfe a day and 750 barrels of oil a day, net to Penn Virginia. With our back in we think the ultimate on that well at this time is probably north of 40 Bcfe. It’s probably one of the better wells I’ve been exposed to. And it does have an offset to drill. Tentatively we think we will try to get [inaudible] sometime next year.

It’s in south Louisiana again because it does introduce some volatility but at the end of the day we have been very successful in projects we have participated in in south Louisiana and the economic returns.

And lastly, in Appalachia, the Marcellus is pointed out. We have accumulated pretty close to 40,000 net acres, part of which we have acquired ourselves, part of which is a result of a AMI that we have formed with a small company in Appalachia who has a very good reputation. Right now, as we speak, we just started a 50 mile, 2D chute up in the northern part of Pennsylvania to evaluate some part of this acreage.

Our plan is, of course, to figure out the structural components of our acreage and tick locations accordingly. We would not expect to do anything probably until sometime the second half of 2009.

And lastly of any significance is the Devoney Shale even though temporarily we have put this program on the back burner for market conditions and product pricing reasons. We did drill two wells in Macon County. That was the area where we were going to go ahead and start a development program. We did complete one of those two wells and that well that we did complete, on a long-term test made about 2.0 MMcfe a day, which is very good for that kind of well. So the plan right now is to take the four wells we have there and to do some long-term testing to make sure we’re confident with the economics before we commit to lay a line out of there.

And I think that’s it, Jim.

A. James Dearlove

Much of what Baird said, certainly not all of that detail, but much of what he said is contained in a release that we put out on October 29 of this year where we updated our operational stuff. You won’t find most of what he said in the November 5 release, you will have to go back to that October 29 one, which is also on our website.

Going back to the November 5 release, just very quickly to finish up on oil and gas, we give you a report in there of expenses, LOE up a little bit for the reasons discussed in there, mostly cost associated with increased compression and some processing fees in east Texas. Texas, other than income, up again basically higher severance taxes due to higher prices. G&A is up because we have been staffing up, particularly in Tulsa during 2008 in the third quarter. Exploration down a little bit, just the ups and downs of the business. DD&A up a little bit, higher depletion rates per unit of productions, some increased drilling costs.

And there are extensive financial tables in the release.

Turning to PVR or PVG for a minute, and I would ask you to recall that while we report our results on a consolidated basis, it’s a frustrating thing for you, an analyst or an owner or an interested party, it’s frustrating for us as well, but that’s what we’re forced to do. If you look back on pages 11 and 12 of the release you will see those numbers broken out in a non-GAAP format that gives you a better snapshot of what oil and gas is doing versus the consolidated numbers.

That’s not to say that PVR and PVG are not important, but at the end of the day, since the companies are so walled off from each other financially, really the important thing, to me, when I wear my PVA hat, is how much cash do we get from PVG and in that respect we had an increase announced by PVG to $0.37 a unit, which is 4% or 5% over what it was last quarter and 30.7% over what it was a year ago.

So PVG has performed very well in the third quarter and we are the benefit of that cash flow. Just to remind you, we own 77% of PVG.

At this point I am going to turn the conversation over to Frank Pici, who is our CFO, to talk about our capital position derivatives and talk about our guidance.

Frank A. Pici

What I will do is focus my comments on the PVA side. Our press release states the PVA and the PVR but I think if you go back to the conference call we had a couple of hours ago on PVR you can get the gist of our comments there with respect to the hedging environment and the capital resources of that entity.

So that said, looking first at hedging, and once again on the Penn Virginia Corp side of the house, you can see that on a consolidated basis we have a large gain reported in the income statement and we sort of normalize that out and we look at adjusted net income.

But that said, I would look at more of the cash impact of our hedging settlements during the quarter on our oil and gas price realizations and in the third quarter the payments we made to our counter parties effectively reduced our natural gas price realization by about $0.48, from a little over $10.00 to $9.66, and our oil realizations by about $7.50 a barrel, which is from about $117.50 down to about $110.00 a barrel. So obviously it’s still very strong price realizations.

Probably more importantly, looking forward on our oil and gas hedging positions, I think we mentioned in the press release that we have got a pretty solid hedging position in place for the fourth quarter. We’re about 55% hedged. We’ve got a weighted average floor and ceiling of 850 x 1115 there. When you take that into 2009 we’ve hedged about 42.0 MMcfe a day. That’s more heavily weighted towards the first part of the year, the winter months in particular, and then the spring and summer and winter of 2009 and 2010 that is going to drop off a bit.

My point being that those are very strong floor/ceiling prices. We, as usual, have used primarily costless collars. Those positions that are currently open, as of early this week, had a minimum money value of about $36.0 million compared to the current strip that’s out there for oil and gas prices. So it’s a good underpinning for our capital program, both for the remainder of this year and as we enter 2009.

With respect to our capital resources and debt position, I know that’s a subject that’s getting a lot more scrutiny these days with the financial market meltdown we’ve had recently, on the Penn Virginia Corp side of the house we ended the third quarter with about $300.0 million available on our revolving credit facility.

What we would expect, given the guidance that’s included in this press release and we will go over briefly in a minute, based on our remaining spending for 2008, we would expect to exit 2008 with revolver availability in the $230.0 million to $250.0 million range. So that gives us a lot of dry powder going into 2009.

We have not yet announced anything formal regarding our 2009 capital expenditures plan. We are working on that now but in general terms I would say we expect to remain, or to put forth a plan that would be much closer to internal-generated cash flow than we’ve been in the last couple of years. Again, that will not put undue pressure on the credit facility and allow us to be sure we can have a balance sheet that preserves capital, so we will continue to do that.

As I said, with respect to PVR, I would refer you back to the conference call we had on that a couple of hours ago. Again, in that credit facility we have some dry powder that we would expect to be able to preserve as well.

Turning for just a second to guidance for this press release and for the rest of the year. Just to make a couple of points and most of these things are explained by footnote in the press release. On oil and gas production we have pulled in the high end of the guidance down slightly from our previous guidance and that was also mentioned in the operations release we put out last week.

And we have also adjusted, somewhat, the capital expenditures guidance from the previous announcement to a range, on the oil and gas side, of $590.0 million to $610.0 million for the full year. So again, a strong capital spending program for the fourth quarter but reduced slightly from what we had previously talked about.

Other items on the guidance table I think remain pretty much similar to what we had in prior guidance so I won’t go through those in detail.

A. James Dearlove

I really can’t add too much. I think between Baird and Frank we got a very good look at the details. I think what you heard is that the third quarter for Penn Virginia was a solid quarter, a very good quarter really, in terms of performance of our oil and gas company, as well as PVR. There was a little bit of an issue at PVR mid-stream, but again that was Ike that wasn’t really an operating –related issue.

We sit here in the fourth quarter all in the same boat. The U.S. and global economies have been rocked by tight credit and diminishing demand and falling commodity prices and if you can tell me what 2009 is going to do you’re a heck of a lot smarter than I am. What I can tell you, and Frank alluded to this, is we are going to be very cautious while we try to be as opportunistic as we can.

We’re not going to put ourselves in a position, if we can possibly help it, where we’ve got some financial gun to our head. That said, you just heard Baird go through, and I thought in good detail, what we’re doing in the Lower Bossier and the Granite Wash, the Selma Chalk, the Woodford Shale. Opportunities make themselves available on the Gulf Coast. We’ve got some interesting, and maybe overstating it, exciting things to do there and we also have some interest in the Marcellus Shale.

So as the year unfolds and if access to the capital markets changes, that’s fine, but as Frank just said going into the year, we are going to try to manage to stay very close to our cash flow. I know that many of you out there are trying to build your models and make your projections and you would love me to give you a bunch of numbers, but I cannot do that.

The budget for next year has not been approved and it won’t be approved until late in the first week or early in the second week of December. When it is, we will put out guidance and we will tell you as much as we can at that time.

With that I would happily take questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Scott Hanold – RBC Capital Markets.

Scott Hanold – RBC Capital Markets

On the McKenzie well, I know you’re not going to throw a rate at us at this point in time but you keep talking in terms of you’re drilling this well, how is it relative to say like the original Fogle well and given what you know, since it’s been on, how does it compare to the Fogle. Or is that not the right way to look at it?

H. Baird Whitehead

That is sort of the right way to look at it. I mean, all three of these wells are sort of acting almost the same. Maybe the Gibson and McKenzie a tad less. But again, the Fogle well, we opened it up and essentially got it down to line pressure within about a month and a half, line pressure being about 600 pounds. In this case we’re holding 2,000 to 3,000 pounds of back pressure intentionally, and they appear to be cleaning up a lot better than what the Fogle well did, so for that reason, they way they’re acting with their short production histories, as compared to what the Fogle well did, I think they’re acting sort of the same.

It’s impossible to draw a curve on a well that, some kind of forecast on a well that is curtailed, on a decline curve analysis. You just can’t do it. It’s got to be under a constant back pressure in order to accurately forecast. So constant back pressure, in most cases, is line pressure when it’s all [inaudible] the line.

So at this time we are pleased with how those two wells are acting.

Scott Hanold – RBC Capital Markets

And with the McKenzie, when did that start cleaning up?

H. Baird Whitehead

It’s been cleaning up for about two weeks.

Scott Hanold – RBC Capital Markets

And could it be another couple of weeks until you have that thing flowing at a pretty nice rate?

H. Baird Whitehead

Since we have only got about 10% out of roughly 70,000 barrels of water we pumped away, this is a lot of water we’re pumping out of these things, and cleaning up at a 700 barrel to 800 barrel water a day rate, you can do the math. It takes some period of time. But as time goes on and you get the bulk of the water out, you know, north of 50%, you’ve have a pretty good idea what you have.

Scott Hanold – RBC Capital Markets

And I think you said the Gibson, you’re not getting back much of the water from that. Why would that be? Is it a pressure issue or is there maybe some pulsing there? What would you attribute that to?

H. Baird Whitehead

That’s the Fogle well. The Gibson well is cleaning up just fine. Just like the McKenzie. The Fogle well is where we had a hard time getting any appreciable water out of it in a short period of time. And I don’t know the answer to that question. Our thinking is, and this is very speculative, is because these pressures at the reservoirs are so high, when you coin these wells hard, the closure pressure, that being the pressure that packs your formation around the sand itself, is so high that there could be some possible damage to that fracture. That’s why people are using these high strength [inaudible].

But whether it’s an embedment issue or some kind of deterioration of the frac itself, I don’t know. But that’s a possible answer.

Scott Hanold – RBC Capital Markets

And you did talk about looking at different ways in completing these wells. What you did with the McKenzie and the Gibson, is that similar to how you did the Fogle? Would it be on sort of a go-forward basis or was there something different in the way you completed the McKenzie well and being on the upper portion versus the lower portion?

H. Baird Whitehead

Actually, the McKenzie and the Gibson are both in the lower portion. We just started recently landing these things in the top. And the reason being is we were seeing our better gashes in the top as we drilled the curve through this stuff, number one. Number two is we were also seeing, based on production laws we ran, at least on the Fogle well, we were actually seeing a larger part of our gas come from this upper part of the Lower Bossier. So that’s how we concluded we probably needed to keep the bulk of this lateral within that upper part of the Lower Bossier.

Scott Hanold – RBC Capital Markets

Is that how other operators are doing it as well?

H. Baird Whitehead

I don’t know. Don’t know the answer to that question.

Operator

Your next question comes from Joseph Allman – JP Morgan.

Joseph Allman – JP Morgan

Could you talk about the cross-activity of the Haynesville line on your acreage?

H. Baird Whitehead

At this time it’s really early. If you remember some of the 17 vertical wells that we’ve talked about that we’ve completed over the last couple of years, it got us into this overall Lower Bossier play.

Three out of those 17 wells we did complete in this Haynesville line. And we had some, I don’t want to say large flow rates because they were not large flow rates, they were anywhere from 200 MMcfe to 300 MMcfe a day. More like what we had in the Lower Bossier.

So does it have some possibilities? Yes it does. It has porosity associated with it, at least based on what [inaudible] tell us. We fracked it, it probably is suitable for horizontal drilling. So that’s what’s so interesting about this whole east Texas area. We continue to find new things to do. All the way from the shallower stuff down to the deeper stuff and maybe there are some deeper ideas yet underneath the salt in this area.

So it’s a very intriguing geological area. I can tell you that. And the more we learn, the more excited we get just based on what we have seen and things to do going forward.

Joseph Allman – JP Morgan

Given some results we have heard recently from other operators in the Haynesville line, are you thinking about testing a well there?

H. Baird Whitehead

Yes. I can’t tell you when we’re going to do that. First on the drawing board is to get comped down in the Upper Bossier. Of course, the most important thing we’re doing is trying to get our Lower Bossier tested across our acreage. But it will definitely be something that we try at some point in time, I just don’t know when.

Joseph Allman – JP Morgan

Are you seeing any abnormally wide differentials or very low well-out prices in any of your places?

H. Baird Whitehead

Where we have seen some basis that has created is up in the [inaudible] specifically. We have seen some basis that has been 3, 350 something like that. So that’s been the only area we have seen some bad things on the basis.

Joseph Allman – JP Morgan

When you are looking at lowering your capex so it’s within cash flow, is that purely just a cash issue or in given the kind of strip pricing we’re looking at right now, are there some plays where if the economics are pretty marginal it’s really not worth drilling at this point?

Frank A. Pici

I wouldn’t say it that way. I think it’s more of a case of just preserving our liquidity at this point and I think that’s the main reason we would to spend closer within cash flow.

A. James Dearlove

I think it’s a fair thing to say that to a degree we will high-grade the portfolio. We will go after the things that seem to have the best return because we want to spend less money but we want to grow our production and our reserves and so we will try to design a program that achieves both of those ends.

Operator

Your next question comes from Sven Del Pozzo - C. K. Cooper & Co.

Sven Del Pozzo - C. K. Cooper & Co.

I was mentioned in the array of the Haynesville wells. I don’t know if you’ve got a more recent map that would allow me to place the newer wells versus the original discovery well. I know you mentioned it just in words. Maybe Baird, you could help me to have an up picture of where the well placements are. You said the McKenzie was 20 miles north of Fogle and Brown well two miles from Fogle, but I’m not sure two miles in what direction. Could you help me out there?

H. Baird Whitehead

Yes. The Fogle-Gibson-Brown, the Fogle development area is sort of down in the southwest of our acreage. I don’t have a map in front of me. We made a couple of small acquisitions last year. That’s where these wells are, to the southwest.

The McKenzie is all the way up to the north of our acreage. Sort of in the tippy-top of Harrison County. And the Gail Fir, which is the other reference point, it’s on the eastern part of our acreage. From the Fogle area it’s probably ten miles.

Sven Del Pozzo - C. K. Cooper & Co.

You also mentioned Stieg 1H and Fogle 7H.

H. Baird Whitehead

Fogle is down in the Fogle area where the Brown and the Gibson. The Steig and the Penny Jones, the Penny Jones is south of the McKenzie. Mileage-wise I don’t know exactly, but if you know how our phase I acreage is with GMX and the northern part of 100% acreage, the McKenzie well being in the northern part of our acreage, the Penny Jones would be about 1/3 down, within that 100% acreage. And the Steig would be yet another 1/3 of the way down, within the 100% acreage. And not too far away from the phase I AMI area.

Sven Del Pozzo - C. K. Cooper & Co.

What might narrow that differential? Is there anything in the foreseeable future that might help lift realizations there?

H. Baird Whitehead

Winter time number one. Number two would be the continuance in the activation of Rex East, over to the east. It should help the problem in the longer term. And more so in the shorter term if we would just have some cold weather.

Sven Del Pozzo - C. K. Cooper & Co.

And have liquids processing at [Mount Belview], is that taken care of now?

A. James Dearlove

Not completely as far as I know. And I’m not the expert and unfortunately Ron Page is unavailable here. But the 1O train, as far as I know, is still down and I think they went down for 30 days and I’m not entirely sure when they started down, but it was within the last week or so as far as I know. So to my knowledge it is not completely up.

Operator

Your next question comes from Irene Haas – Canaccord Adams.

Irene Haas – Canaccord Adams

On your midstream margin, I understand there is some untimely event in the third quarter. Would fourth quarter margin be more like third quarter or slightly better?

A. James Dearlove

That’s a tough one and if you will tell me the places I will give you the answer. I don’t think we know what our margins per se are going to be. Frac spreads have certainly tightened and we have an array of ways of generating income in midstream. One is fee-based and that is about 1/3 of our volume. And that obviously is not necessarily dependent on prices unless people stop drilling.

The POP stuff, as gas or oil prices go down you get damaged there a little bit. And we have done some hedging and we can into that if you would like.

And then on the keep-whole stuff, where the frac spread really matters, obviously it’s a matter of the ratio or the relationship between those oil and gas prices and I really can’t predict them. It’s so volatile.

Frank A. Pici

One thing with respect to the processing margins. Up in the Panhandle of Texas what we have seen is there has been enough of a basis differential there that has actually helped us on the frac spreads that we realize up in that complex. So that has helped some.

And as Jim mentioned, the other thing that is becoming more and more important to the midstream, in particular, is the fee-based revenue. For example, we bought a system up in the Fort Worth Basin this year that is ramping up, increasing volumes and having more wells connected to it as we speak. That is a fee-based revenue stream and that stream will increase and we expect it to increase in the fourth quarter.

So those things all help to offset any weakness in frac spreads or keep-whole processing margins that we make.

The other thing, on the hedging side, we are pretty heavily hedged for the fourth quarter. I think it’s around 75% or so of our midstream production. That should mitigate some downward risk, downside risk, on our processing margins as well.

Operator

Your next question comes from Richard Tullis – Capital One Southcoast.

Richard Tullis – Capital One Southcoast

Looking at the Cotton Valley vertical wells, what do expect your base production decline will be there next year given that you don’t plan to be running any rigs doing verticals?

H. Baird Whitehead

That’s also a place where we see some fairly high impact, like I was talking about with the Lower Bossier. This is going to be an educated guess because I don’t have something here in front of me, it’s probably in the range of about 20% to 25%, as an aggregate.

Richard Tullis – Capital One Southcoast

What is your cost estimate on the Gibson well?

H. Baird Whitehead

It’s going to be around $7.0 million.

Richard Tullis – Capital One Southcoast

Has your thinking on the economics or what you’re looking in the Haynesville wells changed any recently or what sort of cost estimates and EURs are still building into your models?

H. Baird Whitehead

We’re still using about $7.5 million but I think in time we should be able to get our cost down, because we’re getting better at it number one, number two because the cost side of the business is coming down. Probably in the $6.5 million to $7.0 million range.

Richard Tullis – Capital One Southcoast

When do you think you will update the next round of Haynesville wells? Are you going to wait until Q4 results or do you think you will put something out interim?

A. James Dearlove

I think our MO has been to wait until the end of a quarter and unless we find something dramatic we try to avoid putting out on a well-by-well basis because I don’t know that that is actually all that helpful. So it will probably be the end of the fourth quarter. If something dramatic, good or bad, we will tell you, just as we did with that first Fogle well.

Richard Tullis – Capital One Southcoast

The only reason I bring it up is I know we had the first well results back in May and I guess since then we just had the early results on the second well and it might be helpful since you have a good bit of drilling going on, to get maybe an update on several wells at one time, on an interim basis just to help us size up what’s going on, particularly since you are kind of early movers on the Texas side of the play.

A. James Dearlove

I think that’s not a terrible suggestion at all and we will certainly take that under consideration. We all understand what’s going on here. If that McKenzie well, and it’s only one well, but if that McKenzie well has a very positive result, you can make some inferences from that. They are nothing more than inferences. And so if it does, we surely would want to let you know that.

And likewise, if it doesn’t work, if we announce good news we announce bad news and we would tell you that as well. So maybe if we collected a few of these that’s a good idea and if there is some interim operation report we could put out, I’m looking around the table and everybody here is nodding yes, so that’s a good idea.

Richard Tullis – Capital One Southcoast

What about your access to profits in Haynesville-Bossier? Does it look like that’s going to be okay for you?

H. Baird Whitehead

Yes it is. We have had to open ourselves up to more than one supplier, pumping supplier. We typically utilize one company and we’ve had to use two or three companies now to make sure we don’t have a problem. But it has not been a problem here recently.

It is a problem some places. We’ve had to wait for cropping up in the [Mic] line. And the Grant Wash well. So it is a problem for the industry. But we’re such a good customer in east Texas that people try to take care of us.

Richard Tullis – Capital One Southcoast

Do you plan to do any JV wells with GMX in the Haynesville-Bossier?

A. James Dearlove

That’s part of the budget process. I would assume yes, but at this point their budget and our budgets aren’t finalized but I would assume yes.

Operator

Your next question comes from Biju Perincheril – Jefferies.

Biju Perincheril – Jefferies

Next year’s program, the approximately $400.0 million that you have sort of indicated, does that take into [inaudible] and Haynesville all of next year or is there a ramp up?

A. James Dearlove

I think where we stand today is we are expecting to run 5 unless the situation changes, for the better or the worse, over the course of the year.

Biju Perincheril – Jefferies

And that $400.0 million is just a preliminary indication, it’s not a final number.

A. James Dearlove

That’s correct.

Biju Perincheril – Jefferies

How much of that would be for [inaudible] and acquisition versus drilling?

Frank A. Pici

It would be small. Probably, if I had to guess, I would say probably 5%, 6%, 7% would be facilities and lease acquisition.

Biju Perincheril – Jefferies

And then earlier you said you will cut back versus this year. What are some of the top areas that are actually going to be curtailed next year?

Frank A. Pici

We’re going to curtail the Devoney Shale for the time being. We are going to curtail the Hartshorne CBM program. Those would be in the Cotton Valley. At this point in time, assume it’s a $400.0 million in high-grading your opportunities, the Cotton Valley doesn’t cut the mustard. So at least for the time being we would put that on the back burner. But we’ve got most of our leases, held by product in east Texas so that issue is almost behind us.

Biju Perincheril – Jefferies

Will you still continue with some testing up in the back end?

H. Baird Whitehead

Yes. We will try to get a well drilled between now and the end of the year. And we have a new build that’s supposed to show up midyear next year, but our intent would be to go ahead and start drilling wells up there.

Operator

Your next question comes from David Snow – Energy Equities Inc.

David Snow – Energy Equities Inc.

What is the acreage now in the Haynesville?

H. Baird Whitehead

52,000 acres.

David Snow – Energy Equities Inc.

You spent $70.0 million in the third quarter principally on Haynesville?

H. Baird Whitehead

It was about $50.0 million in Haynesville, and roughly $10.0 million in the Marcellus.

David Snow – Energy Equities Inc.

And how much an acre have you had to be looking at down in Haynesville?

H. Baird Whitehead

The max we paid, and it was only for very important acreage in our mind, was about $25,000 an acre. But I think in total for the acreage we picked up from the time we made the announcement of the Fogle #5 well, I think our average cost was about $800 an acre.

Operator

There are no further questions.

A. James Dearlove

Thank you. I see a board here that says there were over 65 of you on the call and I’m sure many more on the Internet, so we appreciate the interest. I congratulate Baird and Frank for doing a great job. We will look forward to talking to you next quarter.

Operator

This concludes today’s conference call.

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