Ranger Oil Corp (ROCC) 2009 Q3 法說會逐字稿

We're about to begin. Good day and welcome to the Penn Virginia Corporation third quarter conference call. Today's call is being recorded. At this time, I would like to turn the call over to Jim Dearlove, President and Chief Executive Officer.

Thank you, operator, and welcome to all of you who have joined the call today. I'm joined here, I'm going to just mention the speakers, by Frank Pici, our CFO, and Baird Whitehead, who runs our oil and gas business And I would point out we have Forrest McNair who is our Controller on the line as well, and then some other folks if we need them.

Let me -- I'm going to more or less follow the release of November 4, yesterday. I won't read it all to you, of course, but I'll try to pretty much just follow along with that.

I'm going to turn the discussion over to Frank when we get to capital resources and other financial matters, as well as to take you through the guidance, but then before we wrap up, the -- I'm going to ask Baird Whitehead to review and summarize the October 30th, last Friday, ops review that we put out because I'm going to guess that's more germane to what a lot of you want to hear about today. So we'll try to close on that and segue into whatever questions you have.

Again, we're talking about the third quarter of 2009 and quarterly production was 2.4 billion cubic feet equivalent or 135 million a day, up 6 -- excuse me, up 6% from the third quarter of 2008 and down 9% from last quarter. The sequential decline was due to an operated drilling moratorium that we imposed upon ourselves roughly six months ago.

However, that -- we actually had better than expected results as we've reported just in the interim, some of the wells we had previously drilled did better than we thought, some of the non-operated wells drilled in the Granite Wash, I think, did a little better than we thought. As a result of that and better results, we've increased our guidance as -- between 1 Bcfe and 1.5 Bcfe and so that would give us at the mid-point of one, that would give us about 50 Bcfe of production this year.

We have resumed, as we said on the 30th, our operating drilling in the fourth quarter, both in the Company-operated drilling both in the Granite Wash in Oklahoma and in the Lower Bossier, or the Haynesville, whichever you would like to call it, in East Texas.

We increased our leasehold acquisition efforts as well in the Granite Wash during the year and the quarter, and we've increased our net acreage there by over 70% from a fairly small number,but Baird will probably touch on that. And in the Marcellus Shale, we expect to meaningfully increase our position this year and next and, in fact, have earmarked $25 million, whether we get it spent or not this year, to be much more aggressive there.

Operating cash flow in the third quarter was $68.5 million, down from a year ago quarter which $97.5 million, mostly due to prices before you adjust for hedges, although -- and our hedges did work, but before adjusting for hedges, gas prices are down two thirds, oil and natural gas liquid prices are down 45% to 55%.

We had a net loss adjusting for the non-cash impacts of derivatives, impairments, gains, losses on the sale of assets of $11.2 million in the quarter. And again, most of that was because of the price driven, just simply declines in revenue. If you -- net loss including these various non-cash items was almost $80 million.

And despite the sequential production decline, cash operating expenses were relatively flat and we expect them to continue to improve as production increases from our drilling -- our resumed drilling in higher margin plays.

On the financial front, and Frank told me I can't steal his thunder, but I'll just be brief, but as we say in the release, subsequent to the end of the third quarter, we were able to complete the syndication of a new three-year revolving credit. It's supported by a $420 million borrowing base, but we've only asked for $300 million, more or less to keep fees down because we're in such a strong liquidity position anyway.

And this new revolving credit is just another element in a program that we put in place early this year to make sure that we exit the year with a very strong cash and liquidity position and that plan worked out, we think, pretty well. We've issued $300 million of high-yield debt, we've raised $65 million in new equity, we've sold a third of our PVG holdings, which are important, but non-strategic, for $118 million and we expect to complete various non-core oil and gas asset sales that might raise between $30 million and $50 million by the end of the year. So over $0.5 billion dollars has been raised by those earning programs and we now leave the year or we will leave the year with an undrawn $300 million facility and in round numbers $90 or more million in cash on hand.

To look a little bit at the oil and gas segment review from a -- more of a numbers point before we hear from Baird, the third quarter, as I said, while production was up, and I sort of led with that because I think that's pretty important, but despite that, during the quarter the oil and gas segment had an operating income that decreased by over $200 million from what it was a year ago. Therefore, we're reporting an operating loss of almost $115 million.

This decrease was due to over $90 million, $92.5 million of impairments, which we'll talk about a little bit, $100 million, $101 million decrease in revenues, which again is a price-driven thing and some other, much smaller items which are mentioned in the release. And again, the decrease in revenues over $100 million was due to sharp declines in commodity prices and I sort of talked a little bit about how much they were down a minute ago.

There was a $103 million increase in operating expenses. Again, $92.5 million of that came out of these non-cash impairments that we talked about, I mentioned at least. Other factors that were -- influenced that number were a $6.7 million increase in DD&A expense, driven to -- as we explained in the release -- driven to a large degree by where we picked to drill and the fact we had some other additional outside expenses.

We also have had $3.7 million of rig stand-by charges this year, which has been fairly consistent -- not consistent in terms of the number, but a consistent element of our reporting since we suspended drilling. And I'll touch on that again in a minute.

As discussed in the release, total oil and gas segment expenses excluding the impairment increased by about $6.6 million or 11%, but operating expenses, particularly LOE and taxes other than income were down a little bit.

To look at those rig stand by charges because maybe they're a little unusual, but as those of you who follow the Company know, in the first quarter of 2009, we opted to defer drilling wells in any of our plays due to the unfavorable economic conditions that the industry was facing. And as a result, we're able to amend some of our drilling contracts and delay commencement of drilling until the beginning of next year.

In the third quarter, we expensed approximately $3.7 million of -- for a lump sum for delay fees and stand-by charges and demobilization fees, etcetera. If we were to not drill at all, we'd incur another $1 million or $1.5 million over the course of the fourth quarter, but we are going to start drilling and, in fact, we have, as we reported last Friday.

We had these impairments, they were charges were primarily, almost $88 million, due to the writedown in the value of approved properties in the Gulf Coast region and these properties have not been sold yet, but we have -- we're evaluating various bids and we fully expect that they will be sold in the fourth quarter. We also sold some of our -- in fact all of our position in the Fayetteville and we will be exiting the Bakken as well.

Let me turn just briefly to the MLP. As you know, Penn Virginia Corporation owns a significant piece of Penn Virginia GP Holdings, which is the general partner of Penn Virginia Resource Partners, an MLP that's in the coal royalty business primarily in the midstream gathering and processing business. We're not trying to de-emphasize that particular investment. It is an important, although non-core investment, but I'm not going to read you very much about it here.

We just completed our quarterly call at 1:00. That call, if it's not up already, will be available on PVR's website, which is PVresource.com, as well as the press releases that go with both PVR and PVG and I would refer you to those for more information on those operations and assets.

However, I would point out that as the owner and general partner, we do report our financial results on a consolidated basis with PVG and in an effort to make it easier for you to devolve and understand what's really going on with the oil and gas Company and the MLP, we give you a conversion of the GMA compliant financial statements -- we convert them to the equity method of accounting included in something called conversion and non-GAAP equity method. In my release, if it's paginated the same as yours, that's pages 12 and 13.

During the quarter, the third quarter of 2009, we sold about a third of our holding in PVG, 10 million units to the public for net proceeds of $118 million, which by the way, are not a gain on our income statement, simply because those are the rules of accounting. It's a little bit frustrating, but that's the way it goes.

However, cash is cash and the proceeds were used to repay the entire outstanding balance on our revolver and the remainder, roughly $68 million, held as cash. As we sit here today, we own about 50 -- not about, we own 51% of PVG and we continue to control the general partner.

PVG continues to pay a distribution. It hasn't raised or lowered that distribution in a year. It has no plans to -- in the immediate future to do either.

We -- it was announced that they will pay their unit holders of record, including us, a quarterly distribution of $0.38 a unit, which annualizes to $1.52, which I just said is unchanged over the last year. That will be paid on the 18th, if I didn't say it that way, to record holders as of the 6th. So with that, I'll ask Frank to talk a little bit about capital resources, etcetera.

Okay. Thanks, Jim. Good afternoon, everyone.

With respect to the new credit facility, I think Jim's laid it out to you and it's also in the press release. I won't read that back to you. Needless to say, we're very pleased with the response of our bank group and a slightly expanded group at the same time, so we think it's a very strong supporter going forward. And, of course, with the new facility, with the undrawns, that gives us upon completion of the final documentation, a $30 billion undrawn line and $90 million of cash as of September as well, so plenty of liquidity there. I think that's probably enough said about that.

With respect to -- I guess a couple of other things -- on the hedging side, as Jim mentioned as well, our hedging activities for the quarter really did help improve our realizations on the natural gas side. It improved our price realization on a cash basis about $1.45 in Mcf equivalent. Year-to-date that's about $1.34. So it's been strong support throughout the year. To put it in absolute terms, that was about a $16 million improvement for the third quarter and almost $50 million year-to-date, so the hedging program has provided good cash flow support for us.

Looking forward on our hedging side, which is primarily natural gas, for the fourth quarter, we're about 70% hedged based on current production rates at a -- we use costless collars as we normally do by and large, and with an average floor of about $6.40, an average ceiling about $8.10. You look at 2010, we're about 50% hedged there at about a $6 floor by $8 ceiling and in 2011 through the first three quarters, a little over 25% hedged at a $5.60 floor and a $7.70 ceiling.

So once again, we think these are strong levels to support going forward to help support our capital expenditures program which we intend to get more aggressive with starting in 2010.

Flipping over to guidance just very briefly, some of the highlights of the guidance table on the back of the release. I'll focus on oil and gas and corporate level items. We covered the PVR-related items in the middle of the guidance table in that call a couple of hours ago and we'll certainly entertain any questions if you have any on this call.

But looking at the PVA and the oil and gas segment guidance items, we have increased our guidance on production slightly from the last quarter and that's primarily because of some improved performance we've seen year to date through the third quarter and what we think will happen as a result of that in the fourth quarter. So we've had an increase in our equivalent production to 49.5 Bcfe to 51 Bcfe.

On the operating expense side, we've tightened that range a bit and one thing to mention there, if you look at that and you look down the page to corporate and other, you'll see that under corporate and other G&A, we've got what appears to be a noticeable increase in our -- from our previous guidance. We've got a $23 million to $24 million guidance number for G&A there.

That's really because we've reclassified for guidance purposes the -- some G&A that had been for guidance included in the cash operating expenses on the E&P side that's really now done under corporate. So we haven't really increased the total cash G&A. We've simply moved it around in the guidance table and the result of that is whenever you look at the E&P guidance, you'll see a range of $1.85 to $1.90. That's a slightly lower range than we had in previous guidance and, again, that reflects this reclass.

You'll see DD&A there, as Jim mentioned, has gone up some, especially in the third quarter. Actuals, based on some -- both cost driven and reserve driven items that affected the quarter -- and that included the properties held for resale that had a fairly large DD&A adjustment on them in addition to the impairment recorded and that spiked the quarter, but going forward, we'd expect that rate to come back down a good bit as you can see in the full-year guidance.

The impairments, of course, have been included in the guidance table now. We would not expect anything of any magnitude in the fourth quarter there.

The other big change there is capital expenditures. That's up on both ends of the range approximately $50 million. That's in two categories in CapEx, development drilling is up about $20 million, and that's really because of the restart, as we mentioned, in our operations release, the restart of drilling, primarily in the -- in East Texas and the Haynesville play, Lower Bossier play as we call it.

And the second large item is in lease acquisition, we -- that piece of guidance is up $25 million to $30 million and that's to reflect an increased leasehold acreage effort in the -- in really all of our core plays, primarily the Marcellus and to a lesser extent the Granite Wash.

Looking down at corporate, I think I mentioned the change there. So I think, Jim, I've covered most of the changes on the guidance table.

All right. Thank you, Frank. Baird, I saved you to be the star of the show, so you can talk about what's going on in the various operations.

All right. Thanks, Jim.

We didn't have a lot of activity, of course, in the third quarter, but it also gave us time to continue to evaluate what we have been doing, especially in the Bossier and the the Granite Wash and get our ducks in a row as we ramp things up currently and going into 2010.

In the Granite Wash, we did drill two gross and 0.8 net wells. The plan is to try to get 5 to 6 net wells drilled before the end of the year. We have drilled almost four net wells through the third the quarter.

Recently things have stepped up in activity, Chesapeake has gone from one rig to three rigs in a matter of about a month or so, and we have also brought one Company-operated -- one Penn Virginia-operated rig started drilling here recently also.

We did complete two wells in the third quarter. One of those wells, the Joshua 116 was drilled in the second quarter, we have about a 60% working interest in it and we also completed a Big Smoke well in which we have a 52% working interest. The Joshua well tested 6.5 million a day, 550-barrels of oil a day or almost 10 million a day equivalent. The Big Smoke Well, which is an excellent well, tested 9.3 million a day, a little over 1,500 barrels a day or about 18.4 million a day equivalent, which is much, much higher than our average for the type curve.

As I said, we have one PVA-operated rig going into next year and, again, these are very, very tentative at this time because we do not have approved budget at this time. But the plan is -- would be to add a second Company-operated rig early next year in combination with our activity -- Chesapeake's activity that they have also said they're going to ramp up in the Granite Wash. We think there will be anywhere from four to six rigs drilling in 2010.

To remind everyone, this is the highest return play that we have in our portfolio. In fact, it exceeds 50% after tax using a modest -- a very modest gas price and for that reason, we've decided to make this a more significant part of our overall portfolio. We have stepped up lease acquisitions as we pointed out in our ops report. We have added about 7,000 net acres here.

In the last three or four months our goal was to get to roughly 10,000 additional acres by the end of the year, which will give us a total of about 20,000 net acres going into 2010 which, by the way, we're going to continue leasing on tentatively.

We do have some of our own ideas, not only would we run the 4 to 6 rigs in our development area with Chesapeake and South Clinton field, but the goal would be to start putting an exploration program together and spud our first exploratory project in the Granite Wash, probably in the second quarter of next year.

Switching gears to Lower Bossier, we, of course, drilled no wells in the Bossier in the third quarter. But again, this has given us additional time to sit back and look at the last two wells we drilled and reported on in the second quarter, that being the James Madison Fur and Steel wells which had respected test rates of 9.6 and 11.4 million a day, with 30-day rates of 6.5 and 8 million a day.

To remind everyone, we had gone from eight-stage frac jobs that we had done earlier on the wells we had drilled, to ten-stage frac jobs on these last two wells pumping actually more sand, more fluid away, in each one of those frac jobs, and actually pumping away up to 3 million tons of sand in the James Madison Fur. We've had both these wells on line now for plus or minus 160 days.

The current rate of the Fur well is about 1.7 million a day with a flowing tubing pressure of almost 1,300 pounds and the Steel well is making 2.1 million a day with about 1,100 pounds flowing tubing pressure. So we still are holding back pressure on these wells over and above the line pressure.

If you look at our type curve for the Bossier in our presentations, as we continue to gather information, we are getting more and more comfortable with the 6 Bcf type curve because of the performance of these last two wells.

We have resumed drilling in the Bossier, as Jim pointed out. We have two rigs that are currently drilling in the Tim's lease and the Brian lease which is in the southern part of our acreage. What we're going to do different on these last two wells is, we're actually going to try to get some longer laterals. Typically we have drilled around 4,000 feet of lateral.

These two wells we're going to try to get to 6,000 feet, so because of longer lateral, the ten-stage frac jobs could be up to 14-stage frac jobs because of the longer laterals that we will try to get drilled. We will continue to run these two rigs in 2010 probably adding a third rig, again, this is tentative, but the Bakken's next year program, of course, would be drilling these Lower Bossier wells.

We will initiate an exploratory program in the upper Bossier and resume drilling in the Cotton Valley, this time not being vertical drilling, but being horizontal drilling. We continue to look at the results of the horizontal drilling in and around us, are becoming more comfortable with those results and because of the liquid content of the Cotton Valley gas, we feel like we can drill some very economical wells in drilling horizontally in the Cotton Valley.

Lastly, you know, I think if you're paying attention to what's coming out of East Texas, I think there's more and more positive information coming out of East Texas. Down in the southern part of our Harrison County acreage, Chesapeake announced a couple of wells to the east of us that were at IP rates of almost 16 million a day.

There was a very recent XTO release of a well to the west of us in northwest Panola County, which is just west of our Harrison county acreage. They had a 30-day rate of about 900 million a day. So even though it appeared that East Texas was put in the penalty box early on, I think as more and more of this positive data comes out, I think that -- I know we feel more comfortable with a 6 Bcf type curve in and around some major part of our acreage.

The Chalk -- the Selma Chalk in Mississippi, again, we had no drilling, in fact, we shut the program down in the first quarter of this year, but again, we continue to monitor. We feel more and more comfortable, again, with a type curve of 2 Bcf that we have for the Chalk.

We have already notified H& P that we plan on adding two rigs or putting the two rigs we had on stand-by back to drilling very early next year and, again, tentatively we would keep those two rigs drilling throughout 2010.

What we plan on trying to do next year different is the typical well we had drilling in Mississippi has been 2,000-foot to 3,000-foot of lateral, that's been for some geological complexes, but our people have gotten much, much better at this. We think that we can continue to push these laterals, again longer and our goal is in 2010 to go from 2,000 feet to 3,000 feet to 3,000 feet to 4,000 feet, which again would mean that we would put more frac stages away and probably increase the number of those frac stages from ten to twelve.

And lastly, the Marcellus Shale, we do plan on spudding our first well, first vertical well around the beginning of December. We will take a lot of time collecting some science information, in fact, we plan on obtaining a full core of the Marcellus itself while we're drilling. It's unlikely that we will get this well completed before the end of the year, but we expect to get it drilled completing it early in 2010. The plan would be at this time is to get this well completed. Let the rig go, get this well completed and soon thereafter bring a rig back that we would drill probably another five to six wells in 2010 and three or four of those would be horizontal and would continue to test both our northern PA acreage and our southwest Pennsylvania acreage.

And lastly, as we pointed out in our ops release, we have stepped up our leasing effort in the Marcellus considerably. We have earmarked around $25 million to be spent in this fourth quarter. We will continue to aggressively lease going into 2010, but the plan is to get to a minimum of 50,000 net acres in the areas that we feel are our most prospective going forward. And with that, Jim, I'll turn it back over to you.

Thanks, Baird, very complete. And let me just -- just a couple of words.

Obviously the dramatic declines in commodity prices, even though we had hedges, which Frank, I thought, described for you very well, in place, nonetheless had a pretty dramatic impact really on our financial results. But to think not so much looking at the quarter, but looking at the year, because I think you got to really -- quarter to quarter, I know we all get judged that way, but the truth is if you're an ongoing concern, I think you've got to think a little bit longer term than that.

The strategic things we did this year, not writing the annual report now, but the strategic things we did this year in terms of shoring up again liquidity and vastly improving our cash position, sure, but also divesting ourselves of things that probably didn't fit the stories well. Nothing wrong with the people involved or the assets themselves, but the Gulf Coast and the Bakken where we weren't going to get traction and this and that, and focusing on what I'll call for the moment sort of portfolio plays where this is where we're going to put our effort, this is where we're going to put our time and our resources and those are the Granite Wash and East Texas areas that Baird talked about there, but in East Texas..

The Marcellus, we're going to hope that works and the Chalk is a -- is kind of a manufacturing process and maybe not very sexy, but we've gotten to be very good at that. So that's where you'll see the focus and as we look back on the first three quarters of the year and now a third of the way into the fourth quarter, we had a plan back in the early part of the year and we think we're executing that plan. And that was to keep your powder dry, take a beating if you don't see growth in production, tell everybody what you're doing the best you can, shore up liquidity, which we've surely done, and get ready for better times. So with that, operator, we're happy to take questions.

(Operator instructions). We'll go to our first question from Scott Hanold from RBC Capital Markets.

Good afternoon, guys.

Hi, Scott.

Hey. On this Bossier trend we're all hearing about quite a bit, it seems like a lot of people are trying to push this play further down south. You know, Baird, can you kind of give some color on what you all know based on the vertical penetrations that you've got up there? This would be the Upper Bossier, not to get nomenclatures confused.

You're talking about the Upper Bossier. I'm sorry.

Yes.

It's much thicker, of course. It's not as organic. The gas in place is not as -- is high, but it does appear to be naturally fractured, at least based on some full core -- one full core we obtained and some natural fractures we have seen in some side wall cores.

I can tell you that as soon as you set pipe through the Cotton Valley, of course, you drill into this upper Bossier and almost immediately your well control issues can start. You see some big gas increases almost immediately, you have to increase mud waste considerably.

We do have some vertical completions in the Upper Bossier and we have sustained flow rates in that Upper Bossier. So for that reason we're optimistic. And one other thing I wanted to say is we actually have, I think, two of our Lower Bossier wells are actually completed in the curve part of the whole -- in the Upper Bossier section and based on some post production logging, we know for a fact this Upper Bossier is making some part of the gas of the total flow stream.

So at this time I know there's not that many data points coming out, but I know Chesapeake has talked about it encouragingly and we're in the same ballpark at this time as far as how we feel that it should perform going forward.

Okay. So you do have a -- some vertical wells that are specifically just in the Upper Bossier, then, is that -- did I hear you right?

We -- we tested -- if you remember, I think we drilled 17 vertical wells in '06, '07 time frame. What we did is we tested smack over by itself and tested those wells for two or three months, came up the hole, tested the Lower Bossier, tested that interval for some period of time and then came up lastly and tested the Upper Bossier and some of the wells. So, yes, to answer your question, we did test the Upper Bossier by itself.

Okay. Any kind of flow rates from that that you can sort of cite or --

Most of the time they were probably about a half million a day, plus or minus.

Okay. All right. And one other question. On that -- the Gulf Coast sale do you all have a PSA in place Is that basically pretty close to being executed and what kind of price range are you looking to get for that asset?

Do not have a PSA in place right now. It is in progress. Price range in expectation will be probably somewhere between $30 million and $50 million.

Okay. Will there be any tax implications on the sale?

Scott, it's Frank Pici. We'll have a tax loss on it.

Okay. All right. Great. Thanks.

You're welcome.

As a matter of fact, Scott, that tax loss helps to -- perhaps with the PVG issue.

Okay. Yes.

Our next question comes from Irene Haas from Canaccord Adams.

Yes, I just want to have a little color on the Granite Wash. You mentioned that you are doing some exploration activity, and I was just kind of wondering whether -- how far on the exploration spectrum these wells will be? Do you need 3-D seismic, are the wash pretty well mapped, are there still some uncertainty, how much would the wells cost and what are you really targeting in terms of recovery?

Irene, we will, in all likelihood, buy a 3-D survey that's already in place across these prospects. We don't expect to learn a lot from the 3-D, but we're going to buy it any way just to have it to make sure we're not letting any stone uncovered.

The good thing about the mid-con, as you know, is there are a number -- a large number of vertical penetrations which helps you immensely on trying to subsurface map a lot of these plays and we are basing these prospects to a large extent at this time based on just well penetrations and just having information.

There, as always, is always a risk on these kind of things, but we know for a fact these wells will make gas. The question is, is the economic factor, so for that reason, there is a risk, but I would expect the recoveries to be very, very similar to what we are seeing in South Clinton, at least based on what we have seen so far.

Some of them may be more oily in some cases, which is not bad, of course, but in general, we think reservoir quality, reserve quality, those kind of things ought to be very similar to what we're already doing.

Thank you.

Thank you.

(Operator instructions). Our next question comes from Welles Fitzpatrick from Johnson Rice.

Good afternoon.

Afternoon.

I was wondering, can you all talk about any plans to zones, other than the B zone, either with your operated rig or maybe just a working interest in a Chesapeake test?

There are some other Granite Wash zones. We have one well that has a C zone interval. It is something that probably can be chased. There's not been a lot of follow up, whether it's -- I don't think there's been any follow up to the one well we have drilled that we ran into the C zone.

But it is some additional upside that's not really been taken into account in anything that we have discussed to date. Probably it's premature, but just having that one data point, of course, is encouraging, so from that standpoint, we will continue to spend more time on it.

Okay. So maybe -- maybe a test sometime in 2010?

I would say so. I mean the B zone, you know, the B zone quality is so so good and we've got some wells that we think ultimately are going to be 10 to 12 Bcf kind of wells in that Granite Wash B zone. But any time you have one well data point that gives you some optimism is something that you've got to pay attention to it and I would think that there would probably be some additional horizontal drilling in it in 2010, yes.

Okay. And with -- I mean the results on the Granite Wash combined with what seems to be relatively cheap acreage costs still, why is the focus sort of shifted to the Marcellus? Is it that there's not that much acreage shaken loose to go a whole lot over the 20,000 net?

Well, we think we need to get to a certain threshold for it to make more sense to us and at least based on where -- parts of our acreage are and based on industry activity, we're very, very enthusiastic about where we are in respect to the play. So, again, it's in our backyard, it's a huge play in size, of course, there's a lot of things to do for a lot of companies and we want to be a participant in the play because the economics are so compelling.

Obviously Baird is talking about the Marcellus, not the Granite Wash.

Great. That's all I got. Thanks, guys.

Thank you.

Our next question comes from Richard Tullis from Capital One Southcoast.

Hey, thank you. Good afternoon. Baird, what's the -- what was the final cost on the Fr and the Steel wells down in the Lower Bossier?

They actually came in less than $8 million, Richard.

Okay.

I think they were around $7.7 million, $7.8 million, something like that.

Okay. What do you -- what's your AFE on the next couple of wells?

Approximately $8 million.

Okay. How much cumulative production on each of those wells?

I think the -- I think the James Madison Fir is about in that 160 days, is about a little over 500 million and the Steel well is a little over 600 million.

Okay. And that's about 160 days as well?

Yes. They were turned in line in a matter of ten days of one another, something like that.

What about after these two wells? What's your next best well or would it be the Fogle?

Fogle's a good well. Fogle has made -- I was looking at that today. It's about around now for 550 days and made pretty close to 900 million.

The Gail Fir 8 and 11 wells are very very good wells, also. These are all down in the southern part of our acreage, so I mean it just continues to highlight why we think the southern part of our acreage is in the right area. The difference in these other ones I'm talking about, of course, is we didn't do the larger number of frac stages and didn't pump as much sand away in each one of those stages, so for that reason we think they're every bit as good if you could compare apples to apples as to these last two wells we drilled.

With your strong liquidity, strong balance sheet, do you see an opportunity to perhaps even high grade your acreage, maybe pick up something that someone else doesn't have the funding for or do some joint ventures, maybe even going east?

We always, Richard, look at that, it's a strategic matter and so I won't -- I certainly wouldn't rule it out.

The acreage that you've picked up in the Granite Wash, how much does that bring you to now?

About 17,000 net.

What was the cost on the additional acreage?

Including brokerage costs, approximately $600, that's with a 12.5% royalty, so very, very good terms.

Okay. And what county is that in?

I prefer not to tell you that.

Okay. And when will you test a well there?

Probably try to get one spudded the second quarter of next year, Richard.

Okay. That's all I had. Thanks a bunch, guys.

Thank you.

Thank you.

(Operator instructions). We'll go to our next question from Mark Lear from Sidoti & Company.

Good afternoon.

Hi.

In terms of the Lower Bossier activity in 2010, is that -- a lot of that going to be focused in the AMI with GMX and just kind of was curious what the overall working interest would be on that activity?

Well, some of it will be, yes. I can't tell you how much exactly because we're still trying to determine where exactly these wells will be. I mean we're prepared to drill 16 100% wells if need be, but having said that, some part of those will be on GMX AMI stuff.

Got you. And are you committing a rig to just drilling the Cotton Valley horizontally for the year or just testing it?

Probably between it and the upper Bossier would keep one rig busy.

Understood. Now, have you drilled -- previously drilled Cotton Valley horizontal?

We have not. But we're ready to go. We've got some locations built, got the engineering behind us, we're ready to go.

In terms of, I guess, looking at the economics and, I guess, how would they compare to what you guys have been looking at in the Lower Bossier?

You know, because of the high liquid consent, about 2.5-gallons in Mcf, and using a 4 Bcf to 5 Bcf type curve for the Cotton Valley, you're talking 25% to 30% after tax rate of return at a $5.50 gas price, $7 oil.

And how does that compare to your model for the Lower Bossier?

Bossier is probably around 20 to 25. So superior? It's actually higher.

Got you. Thank you.

You're welcome.

Thank you.

Our next question comes from Steve Berman from Pritchard Capital.

Good afternoon, most of my questions have been answered, but just one or two that weren't asked. This stuff that you're talking about selling or have sold, the Fayetteville and particularly the Bakken, are we talking small dollars here or could that be something meaningful?

No, it's the former. It's fairly small dollars, both of them are fairly small, Steve.

Okay. So just -- so in terms of monetizations, the Gulf Coast would probably be the biggest, there's really nothing else to -- other than maybe more PVG going forward, there's nothing significant on the horizon?

No. At least nothing planned.

Yes.

I mean there's other assets that would -- you know, we didn't talk about today, that doesn't necessarily mean they're for sale. We don't talk about the hard strong coal, we didn't talk about horizontal CBM, we didn't talk about the lower Devonian Shale, those sorts of things -- Lower Huron shale, excuse me, but no, what we're trying to do, though, is focus on the four plays that I talked about.

And just looking forward maybe even into next year since you're just starting up your drilling program again, but this question is mostly for the Haynesville Bossier, but a lot more companies now are -- seem to be moving in that part of the world towards reporting 30-day rates rather than IP rates to give a little more distance, things like that. I mean do you have any thoughts on that?

I think we've been trying to do that all along and we've been a champion of that. We don't believe in the nanosecond IP rate and have reported 30-day rates and tried to point that out for quite some time.

Yes. I mean I was asking for your view not only for your Company, but just overall, if, you know, maybe --

We can't speak for -- we can't speak for what others are going to do. We think it's a -- as we've said, I just said, I guess, we think it's a far more representative way of saying what's going on and we're trying to do that. We're trying to give you as much color as we can.

I appreciate that. Thank you.

Thank you.

Our next question is from Jeff Robertson with Barclays Capital.

Thanks, Baird. I'm not sure if you talked about this earlier because I missed a little bit of your remarks, but in the acreage that you all are putting together in the Granite Wash, do you have a goal or is there a number that you'd like to get to to make that a -- make the operated part of that play a bigger part of Penn Virginia overall? And then, secondly, are the areas that you've identified for exploration, are those, do you believe, liquids-rich areas or would they be more dry gas or can you shed any light on that?

We don't have a specific goal. To be honest with you, we're trying to get as much as we can when we consider the core part of our exploratory prospects.

So, one of the prospects is much larger than a few of the other ones, probably on the South Clinton size, so because of that, we'll probably -- out of the 10,000 additional acres, we'll pick up probably 7 to 8 of that will be within that larger prospect.

We will continue to lease because we continue to find new things to do in the Granite Wash. The guys in Tulsa have done an excellent job on scouring a tremendous amount of data and for that reason we're finding new things to do.

Some of the Granite Wash will be -- the 90 to 100-barrels per million like South Clinton is. There are a few of these Granite Wash areas that are much, much oilier, in fact, I would almost consider them more of an oil play than a gas play because these are conventional reservoirs, the horizontal drilling should work very well like you're seeing in the Cleveland and Takwan, and the rest of these things, there's no reason why you can't make an oil play very successful horizontally in this Granite Wash. So there will be some very, very oily plays that we will also test.

And if I can follow up, Baird, are the -- is the Granite Wash or are the Granite Wash zones the only or primary reservoir targets in the areas that you all are putting together leases or are there other zones that are perspective as well?

It's primarily the Granite Wash. There are some at Toco Wash, which you may or may not have heard that term, but it's sort of similar and looks the same as the Granite Wash. It would also probably have some potential, but the Granite Wash is our focus right now.

Thank you.

You're welcome.

Thank you.

At this time, there are no further questions. I would like to turn the call over to Jim Dearlove for any final remarks.

Thank you, operator. Again, thank you to all of you that took the time to listen in today. We appreciate the interest. We thought and appreciate the good questions and we'll look forward to talking to you at the end of the quarter.