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Executives

Jim Dearlove - President and CEO

Baird Whitehead - EVP and President, Penn Virginia Oil & Gas Corporation

Frank Pici - EVP and CFO

Ron Page - VP, Midstream

Keith Horton - EVP, Coal

Analysts

Scott Hanold - RBC Capital Markets

Joseph Allman - JP Morgan Chase and Company

Jeff Robertson - Barclays Capital

Josh Senfeld - Canyon Partners

Richard Tullis - Capital One Southcoast, Inc.

Penn Virginia Corporation (PVA) Q4 2008 Earnings Call February 12, 2009 3:00 PM ET

Operator

Greetings and welcome to the Fourth Quarter and Full-Year 2008 joint Conference Call for Penn Virginia Resource Partners and Penn Virginia GP Holdings.

Jim Dearlove

Operator, excuse me, we have the wrong call there.

Baird Whitehead

Penn Virginia Corporation.

Operator

At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the former presentation. (Operator Instructions). As a reminder, this call is being recorded.

It is now my pleasure to introduce your host, Jim Dearlove, Chief Executive Officer of Penn Virginia Corporation. Please go ahead.

Jim Dearlove

Thank you, operator. Just to be clear this is the Penn Virginia Corporation call. Good afternoon all of you. Before I even get started here I will remind you that, over the course of this call we will make some forward-looking statements and that you should bear that in mind that we will do the best we can to be anchored, but there is no guarantees.

I am joined on the call most others by Baird Whitehead, who runs our Oil & Gas Operations; Frank Pici, who is our CFO; Ron Page, who runs the Midstream business; Keith Horton, who runs the Coal business; Forrest McNair, who is our Controller of all three companies.

As the operator said this is full-year and fourth quarter results, I won't read the entire press release to you, of course, I never do but I will try to hit the highlights. The highlights on the first page, I will just [read] here virtually verbatim.

Quarterly, our oil and gas production for the fourth of 2008, and if I forget to say it and I say comparing to something that’s always the fourth quarter of 2007 unless you hear something different. Anyway in this last quarter of 2008 we had gas production as the release says 13.2 billion cubic feet equivalent or about 143.8 million cubic feet a day. As I said that was a new record for us.

Operating cash flow which is a non-GAAP measure was $95.7 million up from $76.3 million in the fourth quarter of 2007. Net income on the other hand was only $300,000 and down from $5.4 million in the fourth quarter of 2007. And then I remind you that net income is heavily influenced by sorts of non-cash numbers from impairments, we had goodwill impairment at PVR that we pick up because we consolidate we had an impairment of some oil and gas properties. We had big swings in derivatives which we trade on a mark-to-market basis. Its not to say that net income or earnings per share are not important, it just they are very-very difficult to compare or to measure.

To try to help with that at least a little bit, we are also putting in a non-GAAP measure that we call adjusted net income, you see that too, of course, down year-over-year and we will get into some of the reasons behind it. For the full-year our production was also a record of oil and gas just under 47 Bcf or 128 million a day that was up about 15% over 2007.

Reserves were up significantly more than the third to very close to that Tcf level at 916 Bcfe, which is up from 680 Bcfe last year.

Operating cash flow was $413 million versus $302 million. Net income was $124 million versus $50 million. Adjusted net income was $108 million versus $72 million.

I would point out to you that these results are not just from the Oil & Gas Company but for all of PVA. There is segment information on page 9 of the release and we do put in some non-GAAP measures, so we reconcile those back on page 11 of the release and we also present our results on an equity method presentation which is on pages 12 and 13 of the release. I realize the release is pretty long that’s why I am trying to guide you a little bit through it.

The release includes a lot of detail regarding the make-up of our numbers and, of course, as I just said we try to provide some fairly detailed financials with both GAAP and non-GAAP results, and we are prepared to discuss those details. However, you would like to question them, but rather than read a page and a half to you let me try to summarize it.

Oil and gas operations saw as I just said record production, lower prices were somewhat of a factor in influencing our results particularly in the fourth quarter. A number of non-cash charges including an asset impairment at PVR which we will talk about here in a minute. Some oil and gas property impairments which I described in the release, mark-to-market derivative adjustments as I said all influenced our numbers, but on an operating cash flow basis you will notice that the fourth quarter in 2008 is I just read you were solidly better than their corresponding periods in 2007.

Operating expenses improved on a currency up basis which is really the way you want look at it, they may have been a little bit higher, but that’s because production was higher. Fourth quarter 2008 exploration expenses were quite a bit higher and that’s because we wrote off some wells and I want to make sure that you understand those wells were in West Virginia. Those are Lower Huron wells this is stuff in our quarter, these are wells which may or may not actually be successful, recently we don't have, we decided to defer the capital to connect them this year by the rules of the accounting they have been deemed non-commercial. We have also expanded some lease hold that we don’t expect to drill on and maybe nothing wrong with it. Its quite obviously not prime lease hold to us.

DD&A expense was considerably higher particularly in the fourth quarter, lot of that has to do with the mix of production. We are in areas with higher depletion rates, and also have to do with some of the fields or legacy fields where reserves are deteriorating a little bit.

Let me just see where. PVR Midstream just to talk for a minute about the NOP, because I am talking about things and influenced our numbers. PVR Midstream despite record levels of throughput volumes particularly in the fourth quarter was heavily impacted by the depressed processing margins that in turn comes about because of natural gas prices and lower NGL prices. For the year Midstream actually had a better year in '08 then it did in 2007, which was the quarter it got hammered pretty good. It also was entity that absorbed that impairment.

The Coal Company, the Coal segment of PVR had a very good year and a very good quarter. Royalty rates were up just because prices were up, production was up as well.

Turning to the Oil & Gas segment of the company, I will read you the headlines and let Baird kind of do the heavy lifting here. Again repeating myself, our approved reserves were ahead 35% over the last year primarily due to the drilling and what we consider I think are literally core areas, which is East Texas, mainly the Haynesville or Lower Bossier depending what nomenclature you would like to use. Mid-Continent and that has meant most recently to us the Granite Wash and the Selma Chalk in Mississippi.

As we said production was up for the quarter and for the year, and I would point out that we put out an operation we leased on February 6th, roughly a week ago and try to go through in great detail what's going on. And Baird I wonder if you could summarize it for us.

Baird Whitehead

Okay, thanks Jim. Some of the stuff were already being in the ops report, but I want to expand upon some of the statistics we had. I am only going to talk about the three places we are spending most of money in 2009.

I will begin with the Granite Wash. By the way all the places I am going to talk about are horizontal in nature. On a Granite Wash side, we have got 16 wells now in line. The average IP for these 16 wells is 12 million a day on a restricted basis. We would like to talk about the average 30 day rates because I think it's more meaningful, because it sustained of course, but the average 30 day rate for 12 wells for which we have this information out of the 16, was 7.9 million a day. We are drilling laterals anywhere from 4500 to 5000 feet a length.

We are typically stimulating these wells with 4 to 5 stage frac jobs through some inter pipe, with about 2 million pounds of sand. If you look at a $5 NYMEX gas price and it correct of course, because of the base difference in the Mid-Continent right now. $5 gas price which equates to less than $4 Mid-Con is 20% before tax rate of return. So, the returns on these stuff are very-very good.

We modeled 6 Bcf well with a drilling and completion cost of $7.5 million. Our fourth quarter production in its play was 13.6 million a day net and it grew from 2.8 million a day net in the third quarter, and we expect to double that production in 2009. We got about 8100 net acres in the play continue to add acreage present day. We expect to drill 12 gross and 6.2 net wells in 2009 and the plan is to drill two off side operator rig that be in Chesapeake, and one company operator rig throughout some part of the year.

Now going to Lower Bossier. We have 13 Bossier wells drilled now with 9 wells in the pipelines, 4 wells waiting on completion and 2 in the process are being drilled. The IP rates for 8 of these wells is averaged 5.3 million a day with a flowing tubing pressure of 4100 pounds and the average 30 day rate for six wells for which we have the information is 3.5 million a day with an average flowing tubing pressure of 2800 pounds.

I know we have talked about this before. We are continuing to learn more and more about this play. This is a tough, tough operational play. There is drilling issues this is abnormally [creating stuff] it's hard to get a frac. We also have some complications as the industry has, but some rupture pipes on stimulation because a defects in pipes we have had 4 wells that have prematurely ruptured which have costs us quite a bit of money to get repaired. And in fact, through the well, not being able to get our stages fraced because of the pipe rupture, but in general, we are making improvements on the drilling side, we are getting these wells drilled routinely now in 45 to 60 days, whereas before it was 60 to 70 days. We are typically fracing these 3500 to 4500 foot [line] collaterals, with 8 stages of anywhere from 500,000 pounds of sand to 2 million pounds of sand. We are treating pressures of anywhere from 9,000 pounds to 9,500 pounds. There is a consideration, on a table now to beef up our pipe in order to take our pressures to 14,000 to 15,000 pounds in order to get some additional sand away but we have not decided to definitely do this.

We are corning one of our wells right now as we speak, we are going to take about a 1,000 foot of full core between the Upper Bossier, Lower Bossier and we are also going to take a core in Haynesville and smack over limes, which we recognize it has some porosity when we drilled the vertical wells back in 2006, early '07.

[Defers] in our year-end reserves are 45 [of these]. If you take a $5 NYMEX gas price correct at the basis, taking into consideration liquids, with the $7.5 million drilling and completion costs it's about a 20% before tax rate of return.

We think there is a good chance that is not 5 Bcf, that is 6 Bcf in north. The problem is you got limited information on these wells, but if you take the same initial rate, and run at different end factors which gives you the shape of the curve, the hyperbolic curve, you can drill from the 5 Bcf to 6 Bcf wells by taking an end factors from about 2 to 2.5.

If you take a 6 Bcf well, and run at $75 gas price, it generates pretty close to 25% before tax rate of return. So, at any case there is a lot left to be learned. You got to remember, we drilled relatively few wells across over 60,000 net acres we have. We have got a lot to learn, and we still are very positive about this play. We think we are going to continue to make improvement not only on the drilling side, but more importantly on a completion side. And at the end the day, I think it's going to meet or achieve our economic expectation.

Right now, we have two rigs as I said, we plan on drilling 12, [gross 8 and 4 net] wells. And we may take on of those wells and drill a horizontal Cotton Valley well because of some industry activity adjacent to our acres that are shown that to be a very positive, very economic.

And lastly in the Chalk, at the Selma Chalk in Mississippi in Glenville and Baxterville fields. We now have 17 of these wells in line, 13 of which have been in line for over 30 days now. The average IP is little over a million a day at 1400 pounds and to 30 day average is about 820 Mcf a day at 1300 pounds. So you see we are not pulling on these wells very significantly. The lateral lengths of the typical well is 2000 to 3000 feet, we treat them with anywhere from 600,000 to 900,000 pounds of sand and 8 to 11 frac stages.

We are now doing us seaming it pipe, we had originally doing this through open hole factors. We have found that it's a seaming of pipe and perforation rod has led to better results. In fact, on our routine basis now the last 2 to 3 wells we have sustained rates on these as well as anywhere from 1.4 million to 1.5 million a day on a restricted basis. So there is improvement that is ongoing in this play.

We model 1.5 Bcf well at a drilling and completion cost of $2.5 million. And before tax rate of return and a $5 gas price again taken into consideration the basis differential is about 18%.

And we have got about 25,000 net acres in this place, so again we have got a lot of running room based on the results of the latter wells we have drilled. I think its 1.5 Bcf is going to closure to 2 Bcf a play, but in any case it’s a very positive play for us. And I think that it from me, Jim.

Jim Dearlove

Okay. Thank you. That was very thorough.

You will notice in the release under the Oil & Gas segment review there is some discussion of some expenses and some results. I don’t know there is anything I need to really call your attention to, I think we are pleased that on an operating basis, on a per unit of production basis, our costs have come down some. We held our G&A fairly flat. Our exploration costs were higher and this gives you a little more color around that $8.8 million of that expense was directed towards on exploratory wells in West Virginia and $5 million was some leasehold expense on things where again we just don’t foresee ourselves drilling.

DD&A was up, if there is any question that we will try to answer them, but I think I did try to touch on that.

The next part of the release deals with PVR, there is a general rule I don’t ask Ron or Keith to really say anything here. We just got over call got over quite a wrong way and put that, we just completed a call an hour ago for PVR, if its not up on our website yet it will be soon that releases up on the website. But I am going to divert from that a little bit today.

I told you call had a very good quarter and very good year, that Midstream had a very rough quarter due to prices, but a solid year. I thought in this environment that we are in, there is so much uncertainty about crisis. We can't give you any certainty, we don’t have any ourselves, but I thought it would be helpful for you to hear from the experts sort of their views on things.

And Keith I would start with you, just if you would give a quick overview of how you see the core market leases impacts on us.

Keith Horton

Well right now, Jim, what we are seeing is rate of spot coal prices that have fallen some 40% to 50% since the end of the third quarter last year. Most of our last year's rating at a contracts during the course of '08, those contracts are typically one to three years in length and they have locked in the prices basically for the next three years about 88% -90% of our production from our property. Most of this coal goes on the steam coal market, we are exposed to 85% to 90% steam and 10% to 15% met.

The met prices are the prices that have actually fallen significantly and drawn the market down. There is a certain amount of crossover tonnage that moves back from the met market into the steam market. But overall, I think 2009 looks like a fairly solid year, there could be some may we pick that but we have taken where we can serve ban on our budget and our forecasting guidance. So, we think we are fairly solid for 2009.

With that I would like to get back to you, Jim.

Jim Dearlove

Thank you, Keith. Ron, I don't know that you need to go through each area but just give a quick overview of how you are seeing Midstream?

Ron Page

Sure, thanks Jim. Midstream obviously the challenge we have currently is the pricing environment, low gas prices and obviously the low crude prices, low liquid prices. So our [people] exposure was hurt in the fourth quarter and will continue to be hurt this year as well as our POP contracts.

As far as our activity levels go we continue to see strong drilling in the panhandles particularly in the Granite Wash, Toka, horizontal Cleveland and actually we recently had our first horizontal Toka well tied into this, we haven’t seen before. But the panhandles our ground drill if will is continues to be strong.

The other areas are holding their own to slightly down in East Texas and flat in the Barnett, where we also have a system. In general we were big toed by the producers that we stay close to who own our systems they believe that even in the current pricing environment they will continue to drill especially in panhandle, the Toka, Cleveland and Granite Wash wells that are being drilled up there right now.

So we feel good about our volume forecast. I don’t know what I can say further I guess about the pricing environment, but we had been moving our contracts more towards fee-based contracts and that’s helping us a little bit right now. And I guess I would remind everyone [they own our] frac spread exposed contracts all of those do have floors in them, so that we get a conditioning fees it goes too much lower.

I guess that’s about it, Jim.

Jim Dearlove

Thank you, Ron. Thank you very much. We have included a section in this report to discuss these impairments, we have included a section on capital resources and derivatives as we always do and of course, our guidance. As is a tradition, Frank could you walk us though that, please.

Frank Pici

Sure. Good afternoon everyone. (Inaudible) impairments and we will talk about the derivatives, the capital resources and the guidance.

On the impairment charges, we had them in both PVA and in PVR, of course, which gets consolidated in. The first on the PVR one, that was our Midstream business, we reported impairment charge of almost $32 million to basically write-off all the goodwill we had reported on three Midstream acquisitions including the initial one we entered the Midstream business in 2005, and two other acquisitions we made in 2008.

Those were really triggered by the decline in commodity prices, and the decline in PVR’s market capitalization which required us to go and do some testing on the overall evaluation of the business. In doing that we found it was justify to go ahead and write those goodwill balances off. Pretty much anybody who has been acquisitive over the last several year's has a similar kind of issue to deal with I believe and I don’t think we are unusual there.

With respect to the oil and gas impairments, again we did it on a fuel-by-fuel basis. Since our successful efforts, that’s why we analyze more impairments. We had triggering events there which were basically the declining commodity price environment we are in. And we went and looked at the undiscounted cash flows in several fields that were close to the edge there and found there were several fields it should be impaired and that’s the $20 million. Impairment on some marginal fields that we have been carrying on our book. So therefore, you see the $20 million charge (inaudible) fields.

Again both of those charges were non-cash in nature. Switching over from derivatives for the quarter, we did have our mark-to-market on our derivative evaluations, we had a big pick up in income as in the derivative evaluation as commodity prices declined again and these positions were therefore worth more in a forward-looking basis. And we recorded a $51 million total derivative income number for the quarter spread along Oil & Gas and Midstream part of PVR. With respect to what on the Oil & Gas side with respect to what really happened to our realizations for the quarter.

Our natural gas hedges provided a $0.42 benefit to our actual realized prices for the quarter, for the full-year we gave about $0.18 back for the quarter and it went into our favor. On oil prices, on the Oil & Gas segment again for the quarter we had a benefit of over $5.23 and for the year it was not the other way about $0.55, but as I said as those commodity prices declined over the fourth quarter we saw some benefit of the hedges.

Going forward on our hedges we were about 50% hedged through the first quarter of '10 with an average flow of about 750. This is natural gas of course average flow of about 750 and the ceiling in the 9 to 11.70 range depending on which quarter you are looking at. Again it's about 50% of our current production volumes.

When we passed out we have actually got some hedges that from the second quarter of '10 through the first quarter '11 at 554 and 870 ceiling this recall us again. And what I am telling you right now this includes a couple of positions that we just put on yesterday, so this is all positions that we got outstanding at this point in time.

So, we want to give you some color that we gone further out on the timeframe and what we got hedged. And we believes those will give good profiting to our cash flow stream going forward.

I guess the other thing I have mentioned here is, we break the guidance as capital resources on the PVR side, they had borrowings at the end of December, $568 million which gave PVR about $130 million of availability on credit facility. We would expect going through the years PVR, since they are going to spend some capital. That the availability will decline somewhat unless, of course, the balance sheet reloaded with another kind of event like either an equity issuance or some other term out of debt.

But we believe we have plenty of capacity to get through the year in our current form. With respect to PVA, we ended the year with about $562 million of borrowing that gave us on our credit facility about $110 million available. Again, we would expect that overtime we probably bring that availability down somewhat given our current capital program and the price environment we are in.

The other thing that will be carefully to keep an eye on will be what our credit facility does and it's predetermination we have supplied our year-end reserve numbers to our bank group. And we will see what kind of borrowing base we get, we would expect there to be some sort of a decline off of the current borrowing base we have got. And we are still waiting to see what effect that has, but in any reasonable scenario, we have looked at, we still have adequate liquidity to get through 2009.

With respect to guidance, there is a guidance table in the release, just to point out a couple of things there. We have reduced our production guidance. We probably saw that in the operation's release we put out last week as well. Main driver for that was some reduction in volume because of being in acting rejection up in the East Texas fields and that reduces our guidance, our production guidance somewhat.

On the cost side, operating expense side, we have increased our depreciation, depletion and amortization guidance slightly. And that's just to reflect a more current look at where we are with our cost basis. In the fourth quarter of '08 we had some adjustments to get our DD&A rates up to current speck given the cost we have seen and some price related reserve revisions that caused our DD&A rates to go up slightly we reflected that in the guidance as well.

With respect to capital expenditures in oil and gas, we have pumped that up slightly from the guidance we provided when we put out the budgets in December.

Most of that is really because of capital projects that were started in '08 and carryover into '09 and that seems to be the bulk of the reason for the increase.

When we look at the oil and gas, excuse me, the coal and Midstream segment. Again on the coal tonnage side we kept that as it was earlier presented we made an adjustment to our other revenues and that's really just price driven on the oil and gas royalties that segments received.

And we made some adjustments on the expense side as well. On the Midstream side, we increased our operating expense to somewhat and that's really a function of offloading some of our capital requirements for some compressors into an operating lease forms so we can serve some liquidity but when it's inflated higher operating expenses as a result.

We have also increased our capital expenditure guidance on the Midstream side slightly, again that's primarily from some capital projects we started in '08 and we will carryover into '09.

So all that said Jim, I think that covers most of the guidance changes.

Jim Dearlove

Thank you, Frank very thorough as always, I overlook one thing I wanted to say when I was talking about PVR and that is that our ownership of PVR is really not that always through PVG, PVG is the public general partner PVR which owned 77% of it and it is important to us because as was previously announced on February the 18th, PVG will pay to it's unit holders a record.

As of the 2nd of February $0.38 a unit or $1.52 per year annualized that's covering the fourth quarter of 2008 and annualized basis that's an increase in distributions by PVG of 19% over what it was last year.

What PVA gets out of that is $11.4 million pre-tax at the annualized that's just under $46 million, mentioned that back when we are talking about the MLP.

But before we go to questions, let me just sort of sum this up a little bit for you if I could.

As we said in the release on one hand we are very, very pleased with our record levels of production our 35% increase in proved reserves the record throughput volumes at PVR Midstream the very strong coal numbers. On the other hand the precipitous drop in commodity prices and more importantly,

I think the tremendous level of uncertainty above future prices and future of the economy, made the future of the world to be dramatic, has made us very, very captious and you see that reflected in our CapEx guidance which Frank just went over with you but again looking at PVOG it’s a third what it was last year.

Despite that reduction from $640 million to $230 million, $235 million sort of pick a mid-point. We hope to increase production, 9% to 13%. We do that because we are drilling these very prolific horizontal wells in those key plays that Baird went over with you.

However we do intend to live within our means and these numbers could change, in fact I would tell you on all candor I was reluctant to put out guidance at all. Because I do not think anyone knows anything about what the future is going to bring. And you are a fool in my opinion if you get yourself over extended to the point that you have a gun to your head.

So we have done the best we could here to tell you where we are and kind of where we are going. But I would caution you that these things are subject very much subject to changes, a less important piece of PVA but an important piece of PVA and I would say the same is true on, when it comes to PVR. This is an important source of cash to us; it has been buffeted by low prices.

And on the Midstream side however like our gas business our Midstream business is very, very well positioned if things turn around.

We are sitting there with a plan in the Haynesville in East Texas, we are sitting there in the Barnett with several hundred thousand acres dedicated to us. We are sitting there in the Rockies with the fee based system with a lot of growth connected with it. And I have not mentioned the care are and that's the panhandle, we will run over in some detail.

But there is quite a lot of drilling going on and there is a lot more detail if you go to the PVR phone call.

So I think we have done what we could to position the company to get through in these tough times, I wish I knew how long they were going to last and when commodity markets improve and capital markets open up. We will be positioned I think to take advantage of it.

So with that I would turn it over operator for any questions that people may have?

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Our first question comes from Scott Hanold from RBC Capital Markets. Please ask your question.

Scott Hanold - RBC Capital Markets

Thanks good afternoon.

Jim Dearlove

Hi Scott.

Scott Hanold - RBC Capital Markets

Baird, you were talking in some detail on some of those Haynesville and the data points that you had there. And you did indicate obviously there was some issues with drilling some wells that probably constrained the rate you could have gotten out of there. When you talked about I think it was the 5.3 million a day average over eight of the wells. Can you talk about what's the subset of the wells the ones that you did not have as many problems with kind of what were some of the averages there. So if you are at 5.3 some of them coming closer to say 6 or 7 million a day?

Baird Whitehead

Yes, yeah the two wells we did not get stimulated in both of those wells I think, this may not be exactly where it is relative out of eight stages. We did get six of them done. I think in both wells. So, intuitively of course its going to have a big effect on your initial rate. So, the 5 Bcf, 6 Bcf numbers I gave you. What that assumes is sort of first day rate of about 7 million a day on an average for the first month of about 5 million a day. But we think that considering we had problems on the wells. And the wells that we worry we get put back together in frac, we had to kill these things and things like that.

So there is some potential damage to the frac job you just put away all these other kind of things I am getting more details and I am sure you want. But every time you get into this kind of killing and well control operations and being sensitive to these kind of pressures. You tend to err on the side of being conservative and there could have been some potential damage to some of the frac jobs we already have been put away.

That's why we feel comfortable with the initial rates or more. But at this point of time we have just taken the I would say a more conservative approach and I think I know it has been batch of wells released by the industry in the 10 to 15 million a day initial rate. I think our wells are probably in that same category.

I do not think we are in a category of 20 to 25 million a day that have been released in the young grove area specifically. There is clearly some differences may be geologic, may be treatments, I can not put my things around at this time. But in general we are going to get better in this over time and I think again the day is going turn out okay.

Scott Hanold - RBC Capital Markets

And by the way I liked the gory details. So I appreciate it but going back to your point. Your type curve assumes 7 million a day, rate of 5 million a day 30 day rate. So you have had a couple of wells that have been in that range I guess is the first of question and then. In reference to your comments, okay so you did?

Baird Whitehead

Yes, [Scott] initial well has been in that category we got a well that we just got turned in line, that we had to shut back in because of some pipeline issues that, I cleared things up in that area. We have got Fogle 6 well, it's in the same category. So we have some wells that have met that.

Scott Hanold - RBC Capital Markets

Okay and then in reference to your comment, and you think you could have 10 to 15 million a day wells on your acreage, I guess what has to be done to get to that point is it well orientation. I mean have you changed the orientation of some of these wells within the shale, yes, and is that what would get you up to those 10 to 15 million a day type of rate?

Jim Dearlove

I think it's part of this. The reason we are taking this drilling the shale consortium it is sponsored by Core Lab. If you get access to some additional data of course of all participants in that consortium. I think yet to be determined and I don't want to say yay or nay. But I know some people who are fracing these wells at higher rates and putting more stand away and much higher pressures and that's why we are considering beating up the casing stream and using some higher rates and higher pressures to get more sand put away.

Whether that can be done or not I do not know but that's a possibility and may be putting more stages where all this stuff cost money, that's the problem. If the trade off of the investment versus return and we got to be cognizant to that. And that's why we want to take this thing in baby steps.

So the answer to your question is yes. I think we also good just by yanking on these wells a little bit harder which we like not to do. But any case I hope that answers your question.

Scott Hanold - RBC Capital Markets

Thank you. One last question on year end reserves, could you all talk about the three P reserves, what that might look like, and when we could get that information? What does the Granite Wash add to that given your recent success there and then if you would could you give us the value of the SEC PV 10 pre-tax year end number?

Jim Dearlove

Well, the three P is pushing treaty right now. The Granite Wash component of that is the three P of that is north 200. I think on the Haynesville three Ps, I think we came up with about 700 Bs, and we did that the first ever conservatively at this time. And through the pre-tax 10% to about $910 million.

Scott Hanold - RBC Capital Markets

$ 910 million and that’s pretax?

Jim Dearlove

That's pre-tax. That’s correct.

Scott Hanold - RBC Capital Markets

Could you remind you used for that?

Jim Dearlove

We're not going it know, come on, Scott, we're not, that’s too much.

Scott Hanold - RBC Capital Markets

Okay. Fair enough. I appreciate it. Thanks.

Operator

Thank you. Our next question is coming from Joe Allman from JP Morgan Chase and Company. Please pose your question.

Joseph Allman - JP Morgan Chase and Company

Yes. Thank you. Good afternoon everybody.

Jim Dearlove

Good afternoon.

Joseph Allman - JP Morgan Chase and Company

Baird, on the Haynesville, I think you said you are looking at cost of about $7.5 million per well. Could you talk about what the cost were for your last few wells and where do you see that going directionally?

Baird Whitehead

Well, with the last two wells have been around $8 million. But we are making drilling improvement. On the rotating days, which is going to bring it down. We also think of course service segment production you are going to come down pump size. So that’s going to bring it down. But, I think the 7 to 7.5, something we do not decide to beef up case extremes and increase hydraulic on the frac jobs. I think we can get it done $7 million and $7.5 million range I think its very doable.

Joseph Allman - JP Morgan Chase and Company

Okay. Its helpful. And then, stepping right in the Haynesville, how about in the Balkan and in the Marcellus Shale, what are your plans for 200p?

Baird Whitehead

Balkan, we had discontinued all operations in fact at this time we are considering I seen of late. If we can get the right compensation for it, with key parties who are active drilling who are adjacent to this. Yet being concerned that's something we're considering. In Marcellus, we still kind of have a well drilled by the end of the year we just finished up on a 50 mile 2D seismic acquisition that will hit the processing here real soon. Of course we are going to utilize that to help pick us locations from the structural standpoint, up in the Northern part of the state. So we are still on track to try to get those couple of wells drilled before the end of the year.

Joseph Allman - JP Morgan Chase and Company

Okay, and decision for the Bakken, is that based on just results that you have seen that haven't been did enough to match where we have we gotten other plays or?

Frank Pici

Yeah, It's simply a portfolio decision. You take what you have got and you put it where it does the most good.

Joseph Allman - JP Morgan Chase and Company

Got you, that's helpful. And Baird, how about this new counter play where the deep Woodword on the Anadarko Basin what are the results looked like out there for you and what are your plans out there?

Baird Whitehead

We drilled one well, we have got half the lateral completed, and it's really just, yet to be to be determine what your results are. We have got the other half lateral, we have not yet stimulated that needs to be stimulated, so it's too early to say this time Joe.

Joseph Allman - JP Morgan Chase and Company

Okay. And then lastly just one for Frank. Frank, if you have any free cash flow available for 2009, or do you plan just paying down debt with that or?

Frank Pici

Yeah, to the extent we have events that’s what we will do, Joe.

Joseph Allman - JP Morgan Chase and Company

Okay. Alright, very helpful. All right, thanks everybody.

Frank Pici

Thank you, Joe.

Operator

Thank you. (Operator Instructions). Our next question comes from Jeff Robertson from Barclays Capital. Please pose your question.

Jeff Robertson - Barclays Capital

Thanks, Baird. Can you talk a little bit about the results from the three different areas, you all are testing in Haynesville, and how they may vary, or is it all fairly comparable?

Baird Whitehead

You know really it is all fairly comparable. We drilled those few wells down in February that appear to be very good wells. Plus I got an other area here over in Houston part of our acres they are appear to be as good if not better, yet to be determine, because this one well I talked about, we just got it in when had back and appears it's going to be a very good well.

Even step up in northern part of our acreage even though we had one well then do as well some wells not far from that well have done okay, and even under $5 gas price would meet our expectation. So at this time, all of our acreage even though there is going to be some areas that they are going to shake out, they are not going to make it. But at this time, I can't say that that's 10% or 5% or 25%. At this point in time it looks okay.

Jeff Robertson - Barclays Capital

Is it much a variation in terms of liquids content or water across from north to the south?

Baird Whitehead

liquids content stuff is extremely low and whatever there is primarily nothing, it's only about 10-30 btu gas. Water wise, we have not seen these wells make a lot of water. In fact, we get concerned about not getting some in principle part of our frac fluids back. so thus the beauty of this play helps the economic a lot. The operating expense on a per Mcfe basis there is a lot less than we experienced on a current value for instance.

Jeff Robertson - Barclays Capital

Okay, thank you.

Baird Whitehead

You're welcome.

Operator

Thank you. Our next question is coming from the Richard Tullis from Capital One Southcoast Inc. Please pose your question. (Operator Instructions). We do have a question coming from [Josh Senfeld] from Canyon Partners, please pose your question.

Josh Senfeld - Canyon Partners

Hi, I have a couple of question is you revolver, is your credit facility secured by your units and PVG. And the second question is what's the minimum amount of fee-based cash that you will generate from the Midstream part of the PVR business or so, fracs?

Frank Pici

This is Frank Pici. The credit facility is not secured by the PVG units. It's secured only by the oil and gas properties. And with respect to your second question about the Midstream, we don't really have a certain percentage, $30 million in PVR.

Jim Dearlove

I don't think he can hear that.

Frank Pici

It's about $30 million of the cash flow.

Josh Senfeld - Canyon Partners

Yes.

Frank Pici

About $30 million in cash flow. That's PVR cash flow that then gets distributed, it doesn't all get distributed, but a portion of that gets included in the distribution paid to all unit holders, it was PVG and its bunch of those units.

Josh Senfeld - Canyon Partners

No, I'm sorry. My question is with regard to the cash flow generated by the Midstream business within PVR, how much of that cash flow is fee-based as opposed to some sort of frac spread were commodity base?

Frank Pici

There is three. Maybe Ron you and Frank should, but there is three kinds of contracts. There is people contract which is your frac spread. There is a POP-type contract that is fee-based. In round numbers they are third in terms of volumes.

Josh Senfeld - Canyon Partners

But Jim even the frac spread exposed contracts have floors in them.

Jim Dearlove

Right.

Josh Senfeld - Canyon Partners

So it’s a difficult question to answer just because it requires assumptions about volume and exactly how the contract split out and pricing.

Jim Dearlove

Order of magnitude, it's not going to be a huge number to PVR's cash flows beyond it, which is simply because bigger components of PVR's cash flow comes out in the coal royalty business. The midstream business is somewhere in the order of 20% of the full cash flow of PVR, and then the of course the key component of the midstream cash flow is a portion of that, so it's going to be a fairly or relatively low percentage of that PVR cash flow.

Josh Senfeld - Canyon Partners

Thank you.

Jim Dearlove

Welcome. Do you have another question?

Josh Senfeld - Canyon Partners

No, that was it. Thank you.

Frank Pici

Great. Thank you.

Operator

Thank you. Our next question is a follow-up from Jeff Robertson from Barclays Capital, please pose you question.

Jeff Robertson - Barclays Capital

I have a follow-up, just if I missed this earlier, but did you all have any Midstream impacts from the fire in Carthage yesterday.

Jim Dearlove

We don't believe so, no Ron. Did we?

Ron Page

No. Our liquids outlet is at Penova pipeline, which is adjacent to the Carthage plant. We, we were notified right after the problem. The explosion or fire whatever it was down at Carthage that Penova would be shutting in. We immediately started warming the plant up and sending liquids to the surge tank instead of instead of pipeline.

Later in the day, we were notified that they had no electricity for pumps, but we were in bypass so we could pump their pressure with our own pumps, we could get our liquids into the pipeline, which we were able to do, so in general we had a very negligible impact.

James Robertson - Barclays Capital

Okay thank you.

Operator

Thank you. Our next question is coming from Richard Tullis from Capital One Southcoast, Inc. Please pose your question.

Richard Tullis - Capital One Southcoast, Inc.

Good afternoon, I apologize for not being on line a little earlier. Going to the LOE, or the cost for the Haynesville wells for your group of wells that are producing right now, which sort of LOE gathering cost are seeing overall?

Baird Whitehead

Well, because this size is so small this time, Richard it's hard to put a definitive number on it, but we think going forward and cleaning up in more in tax there will be around $0.50 per Mcfe. If it goes through the PVR processing facility another $0.30 on top of that for processing.

Richard Tullis - Capital One Southcoast, Inc.

Okay

Baird Whitehead

But $0.50 will be an LOE kind of number.

Richard Tullis - Capital One Southcoast, Inc.

And does that include gathering,

Baird Whitehead

Yes it does.

Richard Tullis - Capital One Southcoast, Inc.

Okay. What about severance tax side, imagine the wells will qualify for the high gas severance tax examination?

Baird Whitehead

That's correct, it will do.

Richard Tullis - Capital One Southcoast, Inc.

Okay, $7 million to the $7.5 million cost, what did Netherland Sewell use for their analysis for the 5B wells.

Baird Whitehead

(inaudible).

Richard Tullis - Capital One Southcoast, Inc.

Okay

Baird Whitehead

That we use 7.5 in that year end report.

Richard Tullis - Capital One Southcoast, Inc.

7.5? Okay. How much cash did you have on hand in 4Q, I may have missed that/

Baird Whitehead

That we have modeled.

Frank Pici

I am not sure about that.

Richard Tullis - Capital One Southcoast, Inc.

Okay.

Frank Pici

I think it was pretty well, Richard, we normally manage pretty much as your balances, because we use any excess cash to pay down debt.

Richard Tullis - Capital One Southcoast, Inc.

Okay. All right, thank you. That’s all the questions I had.

Frank Pici

Thank you.

Operator

Thank you. Our next question is a follow-up coming from Scott Hanold from RBC Capital Markets. Please pose your question.

Scott Hanold - RBC Capital Markets

Yes, thanks. Really quickly on hedging strategy going forward here. You had given this uncertain outlook, what is your thought process and how you approach that?

Frank Pici

Scott, it hasn’t really changed. I mean we still have a target of up to 60% of our EDP is up to two years out. Of course, we are not quite there. And at this point, but we are there for through the first quarter of '10, and it drops down through the first quarter of '011, but at least we have some positions out there.

I know historically has been delayed on position, so we will continue to do that as the opportunity present itself. We tend to try to hit four levels that are at budget at least, and we have been able to pretty much do that historically. Admittedly the most recent position we just put on is a little below what we would have liked from a budget standpoint, but it's in the current environment we are in, we thought it was prudent to put that position on.

Jim Dearlove

Scott, I can't add much to that. Frank and Steve Hartman who is our Treasurer and I think Dana Wright who is our planning guide do a lot of thinking about this and then they dragged [Baird] to vote against it basically, but if anything we got a little bit defensive, I think it's fair to say we have sort of managed through this probability and 98% probability of hitting certain revenue target, which has giving me lot more gory details.

But in this highly uncertain environment that we are in, I mean we are hearing probably the same things you are hearing that. We will see gas under $4 in summer, I don't know if that's true, or it's not, but it makes you pretty antsy, so we got stay true to our philosophy, but on the other and I think we have become a little bit more conservative.

Scott Hanold - RBC Capital Markets

Okay, okay. It sounds like you can be flexible if you get the right opportunity.

Jim Dearlove

Yes, sure.

Scott Hanold - RBC Capital Markets

Okay. I appreciate it. Thanks.

Jim Dearlove

Thank you.

Operator

Thank you. At this time, we have no further question. I would like to turn the call back over to Mr. Jim Dearlove for any closing comments.

Jim Dearlove

Thank you, operator. And I want to thank all of you who are on the call. The screen up here, Jim Dean monitors as you and your families, so is there 77 people on this call and I'm sure there is twice that on the internet.

So, we appreciate the interest and we appreciate the very good questions that were asked, and we look forward to talking to you again hopefully in a better commodity pricing environment with capital markets beginning to open up. Thank you very much.

Operator

Thank you. This does conclude today's teleconference. You may disconnect at this time. Thank you for your participation.

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