Ranger Oil Corp (ROCC) 2008 Q4 法說會逐字稿

Greetings and welcome to the fourth quarter and full year 2008 joint Conference Call for Penn Virginia Resource Partner and Penn Virginia GEP Holdings.

Operator excuse me, we have the wrong call there.

Penn Virginia Corporation.

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

Thank you, operator. Just to be clear, this is the Penn Virginia Corporation call. Good afternoon to all of you. Before I even get started here I'll remind you that over the course of this call, we'll make some forward-looking statements and you should bear that in mind that we'll do the best we can to be anchored but there's no guarantees. I'm joined on the call among others by Baird Whitehead, who runs our oil and gas operations, by Frank Pici, who is our CFO, [Ron Paige] 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'll try to hit the highlights and the highlights on the first page I'll just regurgitate here virtually verbatim. Quarterly, our oil and gas production for the fourth quarter of 2008-- and if I forget to say it and I say I'm comparing to something it's always the fourth quarter 2007 unless you hear something different. But in any rate in this last quarter of 2008 we had gas production as the release says of 13.2 billion cubic feet equivalent or about 143 or 100.8 million cubic feet a day. As I say 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 2007. Net income on the other hand was only $300,000 down from $5.4 million in the fourth quarter 2007 and that I remind you that net income is heavily influenced by all sorts of non-cash numbers from impairments, we had a goodwill impairment at PVR that we pick up because we consolidate. We had an impairment of some oil and gas properties.

We've had big swings in derivatives which we trade on a mark-to-market basis. It's not to say that net income or earnings per share are not important. It's just that they are very very difficult to compare or to measure. To try to help with that at least a little bit, we also put in a non-GAAP measure that we call adjusted net income. You see that too was down year-over-year and we'll get into some of the reasons behind that. For the full year, production was also a record of oil and gas at just under 47 bcf or 128 million a day. That was up about 15% over 2007. Reserves were off significantly more than the third or very close to that PCF level at 916 bcfe which is up from 680 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 now are not just for the oil and gas company but for all of the PVA. There is segment information on Page Nine of the release. 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 & 13 of the release. I realize the release is pretty long, that's why I'm trying to guide you a little bit through it. The release includes a lot of detail regarding the makeup 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're prepared to discuss those details however you'd 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 for asset impairments at PVR were including, excuse me, including an asset impairment at PVR which we will talk about here in a minute. Some oil and gas property impairments which are described in the release, a mark-to-market derivative adjustments as I said all influenced our numbers but on an operating cash flow basis you'll notice that the fourth quarter in 2008 as I just read you was solidly better than their corresponding periods in 2007. Operating expenses improved on a per mcf basis which is really the way you want to 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 you understand, those wells were in West Virginia. Those are Lower Huron wells. This is not stuff in our core area. These are wells which may or may not actually be successful. We simply don't have-- we decided to defer the capital to connect them this year so by the rules of accounting they've been deemed non-commercial. We've also expensed some leasehold that we don't expect to drill on. There may be nothing wrong with it but it's obviously not prime leasehold to us.

DD&A expense was considerably higher, particularly in the fourth quarter. A lot of that has to do with the mix of production. We are in areas with higher depletion rates and it also has to do with some of the legacy fields where reserves have deteriorated a little bit. Let me just see where I am here. PVR Midstream, just to talk for a minute about the MLP, because I'm talking about things that influenced our numbers, PVR Midstream despite record levels off throughput volumes particularly in the fourth quarter was heavily impacted by depressed processing margins. That in turn comes about because lower natural gas prices and lower NGL prices for the year. Midstream naturally had a better year in '08 than it did in 2007 but for the quarter it got hammered pretty good. It also was the 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 and gas segment of the company, I'll read you the headlines and let Baird kind of do the heavy lifting here. Again repeating myself but proved reserves were ahead 35% over last year primarily due to the drilling and what we consider I think our really core core areas which is East Texas namely the Haynesville or Lower Bossier depending on what nomenclature, you'd like to use. The mid-continental, 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 will point out that we put out an operations release on February 6 so roughly a week ago that we tried to go through and break detail of what's going on and Baird I wonder if you could summarize that for us?

Okay, thanks, Jim. Some of this stuff will already be in the (inaudible) report but I want to expand upon some of the statistics we had and I'm only going to talk about the three plays we're spending most of our money in in 2009. I'll begin with the Granite Wash. By the way all of the plays I'll talk about are horizontal in nature. On the Granite Wash side we've got 16 wells now in line. The average IP for these 16 wells is 12 million a day on a restricted basis. You'd like to talk about average 30 day rates because I think it's more meaningful, because it's sustained, of course, but the average 30 day rate for 12 wells for which we have this information, out of 16 was 7.9 mil a day. We're drilling laterals anywhere from 4500 to 5,000 foot of land. We're typically stimulating these wells with four to five stage fract jobs through cemented pipe with about 2 million pounds of sand.

If you look at a $5 NYMEX gas price and you corrected of course because of the base differential in Mid-Con right now, $5 gas price which equates to less than $4 Mid-Con is 22% before tax rate of return, so the returns on this stuff are very, very good. We model with 60 CF well with a drilling completion cost of $7.5 million. Our fourth quarter production in this 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've got about 8100 net acres in the play, continue that acreage present day. We expect to drill 12 gross and 6.4 net wells in 2009 and the plan is to drill with two (inaudible) operator rigs that being Chesapeake and one company operated rig throughout some part of the year. Now going to the Lower Bossier, we have 13 Bossier wells drilled now with nine wells in line. Nine wells in the pipeline, four wells waiting on completion and two in the process of being drilled.

The IP rate for eight of these wells averages 5.3 million a day with a flowing tube of 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 tube of pressure of 2800 pounds. I know we talked about this before. We are continuing to learn more and more about this play. This is a tough, tough operational play. There's drilling issues. This is abnormally pressure stuff. It's hard to get a fract. We've also had some complications, as the industry has, of some ruptured pipes on stimulation because of defects in pipe.

We've had four wells that have prematurely ruptured which have cost us quite a bit of money to get repaired and in fact two of the wells are stages fracted because of the pipe rupture but in general, we are making improvements on the drilling side, getting these wells drilled routinely now in 45-60 days whereas before it was 60-70 days. We are typically fracting these 3500-4500 land laterals with eight stages of anywhere from 500,000 pounds of sand to 2 million pounds of sand with treating pressures of anywhere from 9,000 pounds to 9500 pounds. There is a consideration on the table now to beef up our pipe in order to take our pressures to 14-15,000 pounds in order to give some additional sand away but we have not decided to definitely do this. We are cornering one of our wells right now as we speak. We are going to take about a thousand foot of full core between the Upper Bossier and Lower Bossier and we're also going to take a core in the Haynesville and smackover lines which we recognize has some (inaudible) when we drilled the vertical wells back in 2006, early '07. The pudge in our year-end reserves are booked at five B's.

If you take a $5 NYMEX gas price and take into consideration the liquids with a $7.5 million drilling completion cost it's about a 20% before tax rate of return. We think there is a good chance that it's not 5 bcf, it's 6 bcf and the problem is you got limited information on these wells but if you take the same initial rate and run a different end factor which gives you the shape of the curve, the hyperbolic curve, you can go from 5 to 6 bcf well by taking that end factor from about 2 to 2.5. If you take 6 bcf well and run a $75 gas price it generates pretty close to 25% before tax rate of return, so at any case there's 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 a lot left to learn and we are still very positive about this play. We think we're going to continue to make improvements not only on the drilling side but more importantly on the completion side and at the end of the day I think it's going to meet or achieve our economic expectations. Right now we have two rigs as I said, we plan on drilling 12 gross 8.4 net wells and we may take one of those wells and drill a horizontal Cotton Valley well because of industry activity adjacent to our acreage that has shown that to be very positive and very economic.

Lastly, in the Chalk, at the Selma Chalk in Mississippi and 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 a little over a million a day at 1400 pounds and the 30 day average is about 820 mcf a day at 1300 pounds so you can see we're not pulling on these wells very significantly. The lateral length of the typical well is 2 to 3,000 feet. We treat them with anywhere from 600,000-900,000 pounds of sand in 8 to 11 fract stages. We are now doing this through cemented pipe. We had originally done these through open hole factors. We have find to the cemented pipe and perforation ride has led to better results. In fact on our routine basis on the last two or three wells we have sustained rates on these wells of anywhere from 1.4 to 1.5 million a day on a restricted basis so there is improvement that is ongoing in this play. We model a 1.5 bcf well at a drilling and completion cost of $2.5 million and the before tax rate of return at a $5 gas price again taking into consideration the basis differential is about 18%. And we've got about 25,000 net acres in this play so again, we've got a lot of running room based on the results of the latter wells we had drilled, I think this is going to be closer to a 2 bcf play but in any case it's a very positive play for us, and I think that's it, Jim.

Okay, Baird, thank you. That was very thorough. You'll notice in the release under the oil and gas segment review there's some discussion of some expenses. I don't know that and some results but I don't know that there is anything I need to really call your attention to, I think we're pleased that on an operating basis on a per unit or 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 some exploratory wells in West Virginia and $5 million was some leasehold expense on things where again we just don't see-- foresee ourselves drilling.

DD&A was up, if there's any question we'll try to answer them but I think I did try to touch on that. The next part of the release deals with PVR. As a general rule I don't ask Ron or Keith to really say anything here. We just got over a call-- that's probably the wrong way to put that-- we just completed a call an hour ago for PVR. If it's not up on our website yet it will be soon. That release is up on the website but I'm going to divert from that a little bit today.

I told you, coal had a very good quarter and a very good year but Midstream had a very rough quarter due to precious but a solid year. I thought in this environment that we're in, there's so much uncertainty about prices, we can't maybe 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'd start with you. Just if you would give a quick overview of how you see the coal market at least as it impacts on us.

Well, well right now Jim, what we've seen is really spot coal prices that have fallen some 40-50% since the end of the third quarter last year. Most of our lessees renegotiated contracts during the course of '08. Those contracts are typically one to three years in length and they've locked in the prices basically for the next three years of about 88%, 90% of our production from our property. Most of this coal goes on the steam coal market. We're exposed 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 cross-over tonnage that moves back from the met market into the steam market but overall, I think 2009 looks like a fairly solid year and there could be some negative hiccups but we've taken a very conservative bid on our budget and our forecasting guidance, so we think we're fairly solid for 2009. With that, I'll kick it back to you, Jim.

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

Sure, thanks, Jim. Midstream obviously the challenge we have currently is the pricing environment, low gas prices and then obviously with low crude prices, low liquids prices, so our keep hold exposure was hurting in the fourth quarter and will continue to be hurting this year, as well as our POP contracts. As far as our activity levels go, we continue to see strong drilling in the panhandle, particularly in the Granite Wash, Toka, horizontal Cleveland and actually we've recently had our first horizontal Toka well tied into this that we haven't seen before, but the Panhandle, our crown jewel, if you will, 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're being told by the producers that we stay close to who are on our systems say they believe that even in the current pricing environment they will continue to drill especially in the 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 could 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 that on our fract spread exposed contracts, all of those do have floors in them so that we get a conditioning fee if it goes too much lower. I guess that's about it, Jim.

Thank you, Ron, thank you very much. We've included a section in this report to discuss these impairments. We've included a section on capital resources and derivatives as we always do and of course our guidance and is as traditional, Frank would you walk us through that, please?

Sure. Good afternoon, everyone. I guess I'll start with the impairments and we'll talk about the derivatives and the capital resources and then with the guidance. On the impairment charges, we had them in both CVA and in PBR, of course which gets consolidated in. First on the PVR one, that was on our Midstream business. We recorded an impairment charge of almost $32 million to basically write-off all the goodwill we had recorded on three Midstream acquisitions including the initial one where 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 valuation of the business and doing that we found it was justified to go ahead and write those goodwill balances off.

Pretty much anybody who has been inquisitive over the last several years has had a similar kind of issue to deal with I believe and I don't think we were unusual there. With respect to the oil and gas impairments, again we do that on a field by field basis, (inaudible) successful efforts, that's the way we analyze impairments. We have triggering events there which were basically the declining commodity price environment we're in and we looked at the undiscounted cash flows in several fields that were close to the edge there and found there were several fields that should be impaired and thus the $20 million impairment on some marginal field that we had been carrying on our books. So you can see-- therefore you see the $20 million charge spread among four different fields. But again both those charges were non-cash in nature. Switching over for a minute to the derivatives for the quarter, we did have, we're mark-to-market on our derivative valuations. We had a big pick up in income as-- in the derivative valuations as commodity prices declined again and these positions were therefore worth more on a forward-looking basis.

We recorded a $51 million total derivative income number for the quarter spread among oil and gas and the Midstream part of PVR. With respect to what-- on the oil and 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 but for the quarter, it went in our favor. On oil prices-- on the oil and gas segment again for the quarter, we had a benefit of over $5, $5.23 and for the year, it went 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're about 50% hedged through the first quarter of '10 with an average floor of about 750. This is natural gas of course, average floor of about 750 and the ceiling the 9 to 1170 range depending on which quarter you're looking at and again there's about 50% of our current production volumes.

When you get out past that we've actually got some hedges that from the second quarter of '10 through the first quarter of '11 at a 5.50 floor and 8.70 ceiling, these are collars again and what I'm telling you right now, this includes a couple of positions that we just put on yesterday so this is all positions that we've got outstanding at this point in time. So to give you some color that we have gone further out on the time frame and what we've got hedged and we believe those will give (inaudible) the cash flow stream forward. I guess the other thing I'd mention here is before I get to guidance is capital resources, on the PVR side, they have borrowings at the end of December of $568 million which gives K-PVR about $130 million of availability on its credit facility. We would expect going through the year PVR since they are going to spend some capital that that availability will decline somewhat unless of course the balance sheet is reloaded with another kind of event like either an equity issuance or some other term out of debt but we believe we'll 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 borrowings that gave us on our credit facility about $110 million available. Again, we would expect that over time, we probably would bring that availability down somewhat given our current capital program and the price environment we're in. The other thing that we'll be careful to keep an eye on will be what our credit facility does in its redetermination. We've supplied our year-end reserve numbers to our bank group and we'll see what kind of a borrowing base we get. We would expect there to be some sort of a decline off of the current borrowing base we've got and we're still waiting to see what effect that has but in any reasonable scenario we've looked at, we still have adequate liquidity to get through 2009 at least. With respect to guidance, there's a guidance table in the release, just to point out a couple things there. We have reduced our production guidance. I think you probably saw that in the operations release we put outlast week as well. The main driver for that was some reduction in volume because of being in ethane rejection up in the East Texas fields and that reduces our production guidance somewhat.

On the cost side, operating expense side we've 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 give our DD&A rates up to current spec given the cost we've seen and some price related reserve revisions that cause our DD & A rates to go up slightly and we reflected that in the guidance as well. With respect to capital expenditures and oil and gas, we have bumped that up slightly from the guidance we provided when we put out the budget in December. Most of that is really because of capital projects that were started in '08 and carried over 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 segments, again, on that 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 that segment receives, and we made some adjustments on the expense side as well.

On the Midstream side, we increased our operating expenses somewhat and that's really a function of offloading some of our capital requirements for some compressors into an operating lease form so we can serve some liquidity but when it's inflated higher operating expenses as a result. We've also increased our capital expenditure guidance on the Midstream side slightly and again that's primarily from some capital projects that we started in '08 and we'll carry that over into '09 so all that said Jim I think that covers most of the guidance changes.

Thank you, Frank. That's very thorough as always. I overlooked one thing I wanted to say when I was talking about PVR and that is that our ownership of PVR is really not that at all, it's through PVG. PVG is the public general partner of PVR which owns 77% of it and it is important to us because as was previously announced on February 18th, PVG will pay to its unit holders of record as of the 2nd of February, $0.38 a unit or $1.52 per year or annualized, that's covering the fourth quarter of 2008 and on an annualized basis that's an increase in distributions by PVG of 19% of what it was last year. What PVA gets out of that is $11.4 million free tax and if you annualize that it's just under $46 million and meant to mention that back when we were talking about the MLP.

So before we go to questions let me just sum this up for you a little bit if I could. As we said in the release, on one hand we're 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 about future prices and the future of the economy and the future of the world to be dramatic, has made us very, very cautious 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 of what it was last year. Despite that reduction from $640 million to $230 million or $35 million, to sort of pick a mid point, we hope to increase production 9 to 13%. We do that because we're 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 will tell you, in all candor, I was reluctant to put out guidance at all, because I don't think anyone knows anything about what the future is going to bring and you're a fool in my opinion if you get yourself overextended to the point that you have a gun to your head. So we've done the best we could here to tell you where we are and kind of where we're going but I would caution you that these things are subject -- very much subject to change, as a less important piece of PVA, in that I'd say the same is true on when it comes to PVR. This is an important source of cash to us. It's been buffeted by low prices on the Midstream side; however like our gas business our Midstream business is very, very well positioned if things turnaround. We're sitting there with a plant in the Haynesville in East Texas, we're sitting there in the Barnett with several hundred thousand acres dedicated to us.

We're sitting there in the Rockies with a fee based system with a lot of growth connected with it and I haven't mentioned the core area and that's the Panhandle where Ron went over in some detail, where there's quite a lot of drilling going on and there's a lot more detail if you go to the PVR phone call. So I think we've done what we could to position the company to get through 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'll be positioned, I think, to take advantage of it. So with that, I'd turn it over, operator, to any questions that people may have.

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

Thanks, good afternoon.

Hi, Scott.

Baird, you were talking in some detail on some of those Haynesville data points that you had there and you did indicate obviously there was some issues with drilling some wells that probably constrain the rate you could have gotten out of there but 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 a subset of the wells the ones that didn't have as many problems with and what were some of the averages so if you're at 5.3, did some of them come in closer to 6 or 7 million a day?

Yes. The two wells we didn't get stimulated in both those wells, this may not be exactly right but it's relative, out of eight stages we didn't get six of them done I think in both wells. So intuitively, of course it's 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 and an average for the first month of about 5 million a day, but we think that considering we had the prom zone on the wells and the wells that we were able to get put back together in fract, we had to kill these things and things like that, so there's some potential damage to the fract job you just put away all these other kind of things and I'm getting more details than I'm sure you want, but every time you get into this kind of killing and well control operation and being sensitive to these kind of pressures, you tend to err on the side of being a conservative.

And there could have been potential damage to some of the fract jobs we already had been put away, so that's why we feel comfortable with the initial rates or more but at this point in time we've just taken a-- I'd say a more conservative approach and I think our wells, I know there's been a 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 don't think we're in the category of 20 to 25 million a day that have been released in the Young Grove area specifically. There's clearly some differences, or maybe geologic, maybe treatments, I can't put my finger on it at this time, but in general, we're going to get better at this over time and I think at the end of the day it's going to turn out okay.

And by the way I like the gory details so I appreciate it, but going back to your point, Your (inaudible) it's between 2 to 7 million a day, IC rate of 5 million a day, so you have had a couple wells that have been in that range would be the first part of the question?

Yes.

Okay, so you did?

Yes. The a9inaudible) initial wells have been in that category. We got a well that just got turned in lines that we had to shut back in because of some pipeline issues that I cleared things up in that area. We have a Fogle 6 well that's in the same category so yes, we have some wells that have met that.

Okay, and then in reference to your comment on 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? Have you changed the orientation of some of these wells within the shale yet and is that what would get you up to those 10 to 15 million a day (inaudible) rates?

I think that's part of it. The reason we're taking this core and joined the shale consortium that's sponsored by core labs is to get access to some additional data of course of all participants in that consortium. I think you have to be determined and I don't want to say yay or nay, but I know some people are fracting these wells at higher rates and putting more sand away and much higher pressures and that's why we're considering beefing up the casing string and using something higher rates and higher pressures to get more sand put away.

Whether that can be done or not I don't know, but that's a possibility and maybe putting more stages, all this stuff costs money, that's the problem. It's a trade off of investment versus return here and we've got to be cognizant of that and that's why I want to take this thing in baby steps so to answer your question, yes. I think that we also could just by yanking on these wells a little bit harder which we've elected not to do, but in any case, I hope that answers your question.

Yes, it does, thank you. And one last line of questioning. 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 PV10 pre-tax year-end number?

Well, the three P is pushing three Ps right now. The Granite Wash component of that is the three P's of that is North of 200 B's. I think on the Haynesville three P, I think we came up with about 700 B, and we did that-- approached that very conservatively at this time, and the PV de tax 10%, it was about $910 million.

910 million and that's pre-tax?

That's pre-tax, that's correct.

Could you remind us what other price you used for that?

No, come on, Scott. That's too much.

Okay, fair enough. I appreciate it. Thanks.

Thank you. Our next question is coming from Joe Allman from JPMorgan Chase & Company. Please pose your question.

Yes, thank you, good afternoon, everybody.

Hi, Joe.

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

Well, the last few wells have been around $8 million. We are making drilling improvement on the rotating days which can bring that down. We also think service costs will come down the pumping side so that's going to bring it down but I think the 7 to 7.5, assuming we don't decide to beef up casing strings and increase hydraulic horsepower on the fract jobs, I think we can get it done in the 7 to $7.5 million range, that's very doable.

Okay that's helpful. Stepping away from the Haynesville how about in the [Bakken] and in the Marcellus Shale, what are your plans for 2009?

Bakken we have discontinued all operations. In fact at this time, we are considering exiting that play. If we could get the right compensation for it with a few parties who are active drilling adjacent to us, yet to be determined if that's what we'll do but that's something we are considering and the Marcellus, we still plan on having a couple wells drilled by the end of the year. We just finished up on a 50-mile 2 D seismic acquisition that will end the processing year real soon. Of course we're going to utilize that to help take a slow case and from a structural standpoint up in the northern part of the state so we're still on track to try to get those couple wells drilled before the end of the year.

Okay, and the decision for the Bakken, is that based on just results that you've seen that haven't been good enough to match what you got in other plays?

Yes. You put your hand on it. It's simply a portfolio decision. You take what you got and you put it where it does the most good.

Got it. That's helpful and how about this now Kana play? The deep Woodford, out at the end of (inaudible) Basin, what do results look like out there for you and what are your plans out there?

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

Okay and then lastly just one for Frank. In terms of if you have any free cash flow available in 2009 do you plan on just paying down debt with that?

Yes, to the extent we have any, that's what we would do, Joe.

Okay. Very helpful. Thanks everybody.

Thank you, Joe.

Thank you.

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

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

That really is all fairly comparable. We drilled those few wells down in the Fogle area that appear to be very good wells. We also got another area over in the Eastern part of our acreage that appear to be as good if not better, yet to be determined because it's one less occupied that we just got it in and we had to shut it back in. It's going to be a very good well. Even stuff up in the northern part of our acreage, even though we had one well that didn't do as well, some wells not too far from that same well had done okay and even at $5 gas price would meet our expectation so at this time, all of our acreage, even though it's some areas at the end of the day will shake out, they aren't going to make it but at this time, I can't say that 10% or 5% or 25%. At this point in time it looks okay.

Is it much variation in terms of liquid content or water across from the North and South?

Liquid content and stuff is extremely low and whatever is there is primarily ethane, only about 1030 BTU gas. Water wise, we have not, we haven't seen these wells make a lot of water. In fact we get concerned about not getting the principle part of our fract (inaudible) back so that's the beauty of this play, it helps the economics a lot. The operating expense on a per mcfe basis is a lot less than we would experience on a Cotton Valley well for instance.

Okay, thank you.

You're welcome.

Thank you. Our next question is coming from Richard Tullis from Capital One South Coast. Please pose your question. (Operator Instructions). We appear to have-- we do have a question coming from [Josh Senfeld] from Canyon Partners. Please pose your question.

Hi, a few questions. Is your revolver-- is your credit facility secured by your units in PVG and second question is what's the minimum amount of fee based cash flow you'll generate from the Midstream part of the PVR business if fract splits are no good?

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, I don't really have a set percentage on that. I don't know if you could hear that, but about 30 million of cash flow. Yes. 30 million in cash flow. And 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 of which PVG owns a bunch of those.

I'm sorry, my question is with regard to the cash flow generated by the Midstream business in PDR, how much of that cash flow is fee based as opposed to some sort of fract spread for commodity based?

There's maybe Ron, you or Frank should do this but there's three kinds of contracts. There's a keep hold contract which is your fract spread, there's a POP type contract, there's fee based. In round numbers, they are a third a third a third in terms of volumes, but--

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

Right.

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

Well, let's just say--

On order of magnitude it's not going to be a huge number to PVR's cash flow , to be honest with you, simply because the bigger component of the PVR cash flow comes out of the coal royalty business. The Midstream business is somewhere in the order of 20% of the full cash flow of PVR, and then of course the fee component of the Midstream cash flow is a portion of that, so it's going to be a fairly-- a relatively low percentage of the PVR cash flow.

Thank you. You're welcome.

did you have another question?

No. That was it, thank you. Okay, thank you.

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

I apologize if I missed this earlier but did you all have any Midstream impacts from the fire in Carthage yesterday?

We don't believe so, no, Ron, did we?

No. Our liquids outlet is a Penova pipeline which is adjacent to the Carthage plant. We were notified right after the problem, the explosion or fire or whatever it was down at Carthage that Penova it would be shutting in and we immediately started warming the plant up and sending liquids to the surge tank instead of to the pipeline. Later in the day we were notified they had no electricity for pumps but we were on 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 very negligible impact.

Okay, thank you.

Thank you. Our next question is coming from Richard Tullis from Capital One South Coast. Please pose your question.

Good afternoon. I apologize for not being online a little earlier. Going into the LOE or the cost for the Haynesville wells for your group of wells that are producing right now, what sort of LOE gathering costs are you seeing overall?

Well, because the size is so small at this time, Richard, it's hard to put a definitive number on it but we think going forward including (inaudible) tax that it will be around $0.50 per mcfe If it goes through the PVR processing facility, another $0.30 on top of that for processing, but $0.50 will be on LOE kind of number.

Does that include gathering, Baird?

Yes, it does.

Okay. What about on the severance tax side? I imagine the wells will qualify for the gas severance tax exemption?

That's correct, it will. They're due.

Okay. The 7 to $7.5 million cost, what did (inaudible) use for their analysis for the 5 B wells?

I think you're probably talking about (inaudible) That's who does our year-end--

Oh, okay.

But we use 7.5 in that year-end report.

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

Hang on Rich, we're looking it up.

Okay.

I think it was pretty low, Richard, we normally manage pretty much a zero balance just because we use any excess cash to pay down debt.

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

Thank you.

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

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

Scott, it hasn't really changed too much. We still have a target of 60% of our GDP up to two years out and of course we're not quite there at this point, but we're there through the first quarter of 010 and it drops down through the first quarter of 011 but at least we have some positions out there and our MO historically has been the (inaudible) position so we'll continue to do that as the opportunity presents itself.

We tend to try to hit floor levels that are at a budget at least and we've 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're in, we thought it was prudent to put that position on.

Yes, Scott, I can't add much to that. Frank and Steve Hartman who is our Treasurer and Dana Wright who is our planning guide do a lot of thinking about this and then they drag (inaudible) to vote against it basically, but if anything, we've gotten a little more defensive. I think it's fair to say we sort of managed in this probability of 98% probability of hitting a certain revenue target which is giving you a lot more-- you like gory details, well there is a gory detail but in this highly uncertain environment that we're in, we're hearing probably the same things you're hearing. We'll see gas under $4 this summer. I don't know if that's true or it's not but it makes you pretty antsy, so we try to stay true to our philosophy but on the other hand I think we've gotten a little bit more conservative.

Okay, so it sounds like you can be flexible if you get the right opportunity.

Yes, sir.

Okay. Appreciate it. Thanks.

Thank you.

Thank you. At this time we have no further questions. I'd like to turn the call back over to Mr. Dearlove for any closing comments.

Thank you, operator. I want to thank all of you who were on the call, the screen up here, that monitors you and your families, it says there's 77 people on this call and I'm sure there's twice that on the internet, so we appreciate the interest. We appreciate the very good questions that were asked, and we look forward to talking to you again, hopefully in a better commodity price environment with capital markets beginning to open up. Thank you very much.

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