Ranger Oil Corp (ROCC) 2009 Q1 法說會逐字稿

Greetings, and welcome to the Penn Virginia Corporation first quarter 2009 earnings conference call. All participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). This conference is being recorded. It is my pleasure to introduce your host, James Dearlove, Chief Executive Officer.

Thank you for joining us. Those of you on the call and on the internet. Before we get started, I'll just remind you that over the course of this call, those of us participating in it are liable to make forward-looking statements rather than just purely historical ones, and you should bear that in mind. These can be our opinions or thoughts on things rather than things that are factual, historical facts anyway.

I'm joined here today by Baird Whitehead runs our oil and gas business, Nancy Snyder, our Chief Administrative Officer, Steve Hartman, our Treasurer, Jim Dean, who handles investor relations, remote from us but on the line is Frank Pici, our CFO, and Forrest McNair, our Controller. So we hope with this group we can handle any kind of questions that may come up.

I won't read you the release, but I'll try to follow along more or less in the order it goes. If I miss something, don't hesitate so ask.

First quarter production 152 million a day, 32% over the first quarter of last year and above the fourth quarter of 2008. While production was up, prices that we received for our gas were quite depressed relative to last year, 448 per AM versus 826 in the first quarter of 2008, a change of negative 46% oil, dropped from $97 a year ago to $37 today. And Ngl, natural gas liquids have somewhat decoupled from oil, but they, too, are down from $55 a year ago to $23 today, an 8% drop.

Because of declines in commodity prices, it has had a negative effect on some of our financial measures. For example, operating cash flow which is a non-GAAP measure was $73.4 million versus $84.6 a year ago. We actually had a net loss for the quarter of $7.2 million, where as last year we had a positive net income of $3.2 million. Adjusted net income, a non-GAAP number we include in the front end of the report, that excludes some non-cash items such as derivatives, fair value, rig standby charges which we have this time, and impairments which we have a minor impairment was $2.6 million versus $19.9 million a year ago.

Again looking at PVA as a whole, in other words, the consolidated entity, our operating loss was $7.4 million. In the first quarter of 2008 we had operating income of $60 million, so that's quite a change. What are the components of that? $59 million is in the oil and gas, $16 million of it negative is in PVR midstream, offset a little bit by $7.4 million gain at Penn Virginia Resources coal segment.

The press release spells out many of the factors that impact cash flow and net income, mainly the lower prices, higher interest rates, partially offset by a $36 million increase in derivatives income, mainly from changes in the valuation of the unrealized derivative positions. So in short, our hedging programs have been very beneficial.

Now, I think what I will do now is discuss the oil and gas segment. Baird, I prefer you to take us through that.

Like the last conference call, I was going to bring you up to date on the play session which we are spending money this year and going forward. First of all start with the Granite Wash. In the first quarter we drilled 4 gross and 1.8 net wells. The IP's for these four wells ranged from 9.8 million to 14.6 million a day with average of almost 12 million a day. To date, or since inception of horizontal drilling, we had 19 wells on line, producing 66 million a day gross, for almost 21 million a day net to Penn Virginia. The IP's for these wells we have in line have averaged about 10.1 million with a range anywhere from 3.7 all the way up to almost 21 million a day . So you can see the range, but the average of the wells is very, very attractive.

For the 30 day rates which we like to talk more so about for the 16 wells we have in line, that have met the criteria, that rate is 7.5 million a day. To remind everyone we typically drill anywhere from 4500 to 5000-foot laterals in this play. We frac from anywhere from 4 to 5 stages with cemented pipe and perforated and put away from 1.5 to 2 million tons of sand. Last year or late last year we were modeling the wells at 6 bcf equivalent, with a drilling and completion cost of $7.7 million. That same well today, we are using drilling and completion cost of $6.3 million. So the costs have come down considerably in a fairly short period of time.

The last well that Penn Virginia that was drilled in the first quarter, we actually drilled that well for less than 6 million a day. We model these wells with a IP of 8 million a day. And 80 barrels per million of liquid. So these are very liquid-rich wells which, of course, healthy economics especially with the btu disparity in price between oil and gas. So if you take the 6 bcf well and $6.3 million, rates of returns -- the after tax rates of returns on these wells, even taking into account the negative basis, significant negative basis, we are talking north of 30% after tax rate of return for the wells.

At this point in time, this is the best play we have from a pure value economical standpoint. Remind everyone we have about 10,000 net acres in this play, we have about 90 locations left to drill. This year, we will drill 10 gross and 4 net wells. So we have about two net wells to drill between now and the end of the year. In the Woodford Shale, we haven't talked a lot about that and we really haven't spent a lot of money on that play type, especially first quarter, and have no further plans for the remainder of the year. I just wanted to bring you up to date. Over the last little over a year, we drilled or participated in 17 wells, 16 of those wells are in line and net production to Penn Virginia from those 16 wells is 2.5 million a day. So our interest is fairly low, but if you look from a growth standpoint, average IP of those wells is 3.5 million a day, with a range of anywhere from 1.5 to 5 million a day, and 30 day IP is 3.3 million a day, almost as high as the initial IP.

In any case, we think the reserves on a per well basis on the wells we drilled are about 3.4 bcf with a drilling completion cost of anywhere from $4 million to $4.5 million. We have about 35,000 net acres in the Woodford and Arcoma alone, where all the 17 wells have been drilled. And again, with a modest increase in gas price it's another play type we like to do, so we could invest money drilling these kinds of wells.

Now to talk about everybody's favorite subject, the Lower Bossier. We have drilled 15 wells to date, 13 of those wells are in line. We finished up drilling the last two, which are waiting on completion in the first quarter. Penn Virginia drilled 6 gross and net wells, with IP's of anywhere from 2.8 to 8.3 million a day, with an average of 5.4 million a day. The Gail [Peratage], one of the wells we drilled in the first quarter, had an IP of 8.3 million a day, which is actually second highest IP well we have drilled since inception. The [Fullby Five Discovery] well at 8.8 million a day is actually the best well we have drilled to date. We also announced earlier, we drilled the Agnor 6-H which tested the northern limits our acreage. In all practical purposes, it was unsuccessful. Even though it's making little bit of gas at this time. If you take the 13 wells, that we do have in line, IP's of those 13 wells are about 5 million a day, with an average flow and to pressure of 3600 pounds.

In general, what we tried to do over the last year or so is to get our acreage tested all the way from south to north. As a result, we knew as we went further north for both geological reasons and gas content reasons, there was some risk of drilling lesser quality wells, but we felt we had to do that in order to get our arms around the most prospective part of our acreage. So our average for all wells we drilled has been depressed to some extent because of some of these wells we drilled in the northern part of our acreage.

Over the last 4 or so wells, we made some adjustments to our drilling. We are now drilling our laterals and specifically in a direction of 25 degrees west and north. We are landing the lateral essentially in the top of the lower Bossier which has a higher silica content and and has higher affected porosity. We're running a heavier weight casing which allows us to maximize the ability to get our [frac jaws] put away because of pressure.

In general, our drilling efficiencies improved significantly. We have taken the drilling days all the way down to about 30 days on the last two wells drilled, and from spud to rig release on these last two wells drilled, they were 43 and 38 days, respectively, which is a significant improvement from where we started this play just about a year ago.

In fact, we are drilling these horizontal lower Bossier wells about the same period of time it once took us to drill the Cotton Valley vertical wells three years ago. So you can see the progress we have made. It's not only the result of experience factor of both us and the drilling contractors, but things like bit selection, we taken it from ten bits all the way down to four bits. All this helps, of course, in driving the costs down. Lateral lynch that we have drilled typically are anywhere from 3500 to 4500 feet. We have fracked these things with up to 8 stages of anywhere from half a million on the tougher wells and trying to get sand put away, all the way up to 2 million pounds of sand.

We have been cautious as far as how many stages to put away and how big each stage needed to be. You can get a lot of money tied up in the frac jobs I know that there are people pumping more stages than we are. At least at this time, we felt the 8 stages were adequate because of the microseismic program we have done on some wells which, between that and limited entry on the frac job, showed we were effectively stimulating the reservoir. And because of the cost side, you can get all the way up to $2.5 million to $3.5 million dollars tied up on some of these higher stage frac jobs, that is a ton of money.

We tried to keep our frac jobs $2 million or less, and at this point in time that's what we have done. We don't question if you pump more stages away and pump some bigger jobs, you are going to get higher up front rates. There may be some acceleration benefit because of that, but is there really a present value benefit from a incremental cost. Right now, we don't know that. We are going to participate in a fairly rigorous reservoir modeling study that we have joined by an outside consortium that will help us and participating members to understand the reservoir since we are dealing with a complicated shale.

In any case, until we get that figured out, we are concerned about spending a ton of money on frac jobs because we don't know the benefit at this time. Ultimately, the reserves may be the same of a well utilizing more frac jobs versus less. In any case, it is our plan to get this figured out with the reservoir modeling. We did take that 1000 foot core on our formula well in the first quarter.

We have learned quite a bit. There is a lot left to learn since the core is going to be under evaluation for up to a year on trying to get frag barrier information and those kind of things. But in any case, based on some of the laws we have run in general, and utilizing laws to estimate gas in place, we think primarily in the southern part of our acreage we are dealing with about 160 d's of gas in place, or 640 acres on our southern acreage. If you use about a 50% of our acreage is perspective in that kind of well that you want to routinely drill and use in a 20% recovery, we about 1.3 T's of gross gas on the southern acreage. If you take a 25% haircut for various reasons, we're still about a bcf. And at the same time, the core has identified some other zones, some other horizontal opportunities we will try to take advantage of in the years to come.

In general just to say a little bit more, I know I'm talking a lot about this, we have learned the our southern acreage is the most respected. If you take the wells we drilled down there, which is 8 wells, and taken into account a few problems we have with some of the 8 wells we drilled because of casing problems, we have an average IP of 6 million a day on those 8 wells. So on a going forward basis taking in account what we know, taking into account a tight curve we think is from 5 to 6 bcf that would assume a 7 million a day initial rate, that would assume the first month average 5 million a day.

But we think we have a number of opportunities to drill under that scenario, we have some wells in the southern acreage we think exceeds 6 bcf, that being the [Fogo 6], the [Fogo 5]. A couple of the recent wells we drilled like the Gail [Peratage] and the [Foreigner] well. In any case I think once we're on a routine basis down in our southern part of our acreage, we can duplicate this 8 million a day kind of initial rate we have seen on some of our wells. Lastly the Chalk, Summit Chalk in Mississippi, we have 20 wells in line right now with an average IP of little over a million a day. At 1400 pounds on a 30 day average, about 800 mcf a day. We have routinely fracked these wells 8 to 11 frac stages. We originally did them utilizing open hoe packers. Now we are using cemented and perforated casing through stages.

The 30 day average for a cemented encased well versus one using an open hoe packer, and these are just on horizontal wells now, is about a million a day as compared to about 750 mcf a day. If you look at the 60 day average, that actually increases to 1.2 million a day, versus 800 a day. If you actually go to 90 days, that average actually increases to 1.5 million a day verses 750. So we seen a huge difference on cementing our casing and perforating it and fracking that way versus utilizing the inflatable packer. So that play has really taken on some big improvements over the last year . We're modeling these wells at about 1.5 b's at $2.5 million dollars. I think based on what we seeing recently with the case hole and perforated jobs, we think the averages are closer to 2b's now. And even if you use a 450 gas price, with about $2.5 million dollars, still about a 15% after tax rate of return. And we think we can continue to drive the cost down on that play.

Lastly, on the Marcellus, even though we are not doing a lot this year, we have one well planned to drill. Vertical well, we shot 50 miles, up in the northern part of our acreage. We have roughly 38,000 net acres in the play between northern tier, Pennsylvania and southwest PA. Looking at the industry activity both horizontally and vertically, we think our acreage is in the right areas. But until we drill our first well or two, we don't know. That is something we are excited about trying to get tested at some point in time. With that, Jim, I will pass that back.

Thank you, Baird. I wish you would be more detailed next time. But anyway. All of you on the call, we have your names and numbers, and there will be a test. A lot of what Baird said is contained in the operations release which came out on May 1 and available on our web site.

As I reported earlier, the oil and gas segment operating income decreased by $59 million relative to a year ago, and included in that loss was $9.9 million of rig standby charges, which resulted from our decision to defer drilling in several of our plays. We just don't think it's probably prudent to be drilling and producing gas that's not going to go anywhere in this price environment, so we have deferred some of that. If we choose to have that decision stand for the whole year, we would incur another $14.8 million of charges which is discussed in the release.

The release talks about segment expenses in the oil and gas arena, excluding rig and standby charges, and $1.2 million impairment which was merely caused by lower prices. Our cash expenses increased to $5.56, from $5.32, but you've got to look inside of those numbers, and when you do you find that our cosh operating expense -- our cash operating expense, total segment experiences cash operating expenses -- total segment expenses increased from $5.56 to $5.32.

Looking inside the numbers, the cash operating expense decreased on a per Mcf basis from $2.34, in the first quarter of 2008 to $1.80 right now. Specifically LOE decreased from -- to $1.08 from $1.35 as service costs and well disposal costs were reduced. Taxes other than income also decreased, of course, because commodity prices did, so severance taxes went down. G&A went down on a per mcf basis because we are spreading it over more mcf.

What went up? Exploration expense increased to $11.4 million from $4.7 a year ago,primarily due to $6.2 million of increased amortization of unproved properties and DD&A went up to $2.92 per m from $2.53 per m simply because of higher drilling costs and expenses with more expensive leasehold acquisition. So again, this is detailed for you and there is pages and pages of numbers in the report. I'm just trying to give you an overview.

In the first quarter we opted to defer drilling in several of our plays to due to unfavorable economic conditions. The drilling companies buying ours are willing to work with us, and as a result we amended certain contracts to delay commencement of drilling until 2010. If we want to, if for some reason things get better, we can revisit some of that. On the PVR, PVG front, we had a conference call two hours ago at 1:00 eastern time, that is available on a web site PVResource. com, available this afternoon or tomorrow for sure, you can listen to it.

I'm not going to spend a lot of time on PVR and PVG. I will say that the coal segment of the underlying MLP, Penn Virginia Resources, increased operating income by $7.4 million or 42% to $25 million in the first quarter due to a 15% increase in lessees production and a 12% increase in royalties.

PVR Midstream, the other segment of the MLP, on the other hand reported decrease of $16.7 million in operating income, which resulted in a $3 million operating loss. That was simply due almost entirely to the collapse of commodity prices, mgl prices, which and gas prices we have some flex spread driven contracts they were affected. Our POP contracts, of course, are also affected because gas and oil prices have come down. On the other hand, there seems to be firming of oil and ngl prices in April and end into May. The other thing I would say is we have a hedging program at PVR as well for the Midstream piece, and that certainly paid off for us as outlined in the release in the first quarter.

Perhaps the most relevant thing to PVA shareholder is the announcement I made the 20th of this year. PVG of which we own 77% in, is nothing more than the public general partner of PVR and simply a pass through vehicle, that entity will make a quarterly cash distribution to unit holders on May 4 of this year of $0.38 cents, which is$1.52 annualized that covers the first quarter of 2009. That's a 12% increase over what it was in the first quarter last year, but unchanged from the third and fourth quarter this year. I would just remind you in all of this PVA, PVOG, PVR, all of this alphabet soup, we try to make the financial statements more readable, and that is on pages 11 and 12 in the release where you see on the equity method how things look. That collapses all of the PVR stuff to a line item and makes it clearer for you.

I would ask Frank Pici if he would talk about capital resources derivatives and, Frank, maybe touch on our guidance as well.

Good afternoon, everyone. I will start with derivatives, a snapshot of what impact they had on the quarter and then going forward, what they look like. For the quarter as we stated in the release, the oil and gas company received over $16 million of cash settlements, what that affectively did is increased the natural gas price realizations from what you see in the release, the cash realization was $4.48. Cash market, but what including the settlements on the derivatives that increased the realization another $1.27 to $5.75. It provided nice support to our cash flow stream for natural gas.

On the oil side which is a much much smaller position, it increased realizations from $37, little over $37 to almost $45, so again, good support to the realizations. Going forward, based on our current production, we are about 70% hedged for second and third quarters, about 65% hedged in the fourth quarter of 2009. What I think is more important, normally done with a combination of callers and a few swaps thrown in. But if you look at the average floor price of the positions in the second and third quarter, the floor is $6.40 roughly if the fourth quarter at $7. Again these positions provide good support to the gas prices. When you go in to 2011, 2010 and the first quarter of 2011, we are 25% hedged for those quarters, those five quarters. And again, the average floor price of those positions is $5.40, roughly. Again, we think that provides good down side protection and good support to the cash flow stream.

I won't get into PVR derivatives, they were discussed in the other call, we will be happy to field questions if you have any on this call. With respect to our capital resources, I won touch on PVR, although they had an increase in their credit facility. On the corporate side we have with our recent redetermination in place at $450 million, at the end of the quarter, first quarter, we had $60 million of liquidity, that is a little tighter than we like it to. We have probably from the operations release, in response to that we got liquidity and in these low gas price times, we cut our capital program to ensure that we drill only economic project, number one, but also preserve liquidity, number two. We will continue to look at ways to enhance that liquidity as we go through time and in the longer term to lower dependence on the bank debt going forward.

Touching on the guidance, there is a guidance table back on I believe it's page 13 of the release. I will not address the coal and natural resource and Midstream segments as they were discussed in the previous call. On the oil and gas segment, we have not changed our production guidance from previous guidance at 48 to 50 bcf for 2009. So that's remained the same.

We made downward adjustment in cash operating expenses. Our first quarter was much less than the prior year's first quarter. And again, we brought that down from prior guidance of $2 to $2.10 per mcf equivalent, to $1.85 to $1.95. We think that's both the lower water disposal cost and different production mix.

On the exploration side, we increased that guidance on expense from $20 million to $25 million, to $60 million to $70 million. Again, that's the things Jim talked about, being the increased unproved property amortization costs, and the expected rig standby expenses if things remain as they are today. No real change to DD&A with respect to capital expenditures. We have reduced guidance that was in the operations release from $210 million to $220 million down to $130 million to $140 million. What that means is based on what we spent in the first quarter that we expect spending in the last three quarters of $44 million to $54 million.

Again, we believe we can fund that with internal cash flow, more than fund that with internal cash flow, the distributions we get from PVG, and if we need a little bit of revolver support, we will get it from our credit facility. Jim, I think that's the bulk of the guidance changes.

Thank you, Frank. Let me just wrap up before we turn this over to questions. Like many companies in our industry, we have been adversely impacted by declines in commodity prices and hampered by the turmoil in the financial markets. In spite of these conditions, I think we are pleased really with our performance during the first quarter of 2009. A 32% year-over-year growth in oil and gas production, and 6% sequential quarterly growth with improving costs, I think is a testimony really to the quality of our people and of our plays.

Frank took you through the guidance and, in addition I guess I would say the strong start that we've had in the year despite what we are doing in terms of reducing CapEx, we think we are going to have an increase in production year-over-year. So I think given the environment that we trying to operate in, we are reasonably pleased with the quarter. So with that operator, I would turn it over to questions.

Thank you. We will now be conducting a question-and-answer session. (Operator Instructions). First question is from Scott Hanold with RBC Capital Markets.

Good afternoon.

Hi, Scott.

I think this is a question for Baird, when you look at Hainesville shale rates at this point in time, you all say that your current production rate, about 20 million a day from 13 wells, that I guess implies somewhere around 1.5 a day, per well. And can you give us color on that? Have the wells been performing as you expected, the more recent ones, and is it is weaker initial ones that you had issues with dragging down that average?

That's exactly right. Some of the wells we drilled to the north had the lower initial rates and had steeper declines, some of those wells have settled in at less than a million a day. Some of the wells in the southern part of the acreage, which in general is a very very good area, and we feel we can develop going forward. Some of those wells have been hindered we had casing problems early on, we didn't get all the frac stages put away because of casing issues. And for that reason, production wasn't optimized. So it's a combination of both.

To answer your question, if you take a well down in the southern part of the acreage that would be not hindered by problems per se, like the [Fogel 5] and the [Fogel 6], we think those are 6.5 to 7.5 bcf wells now, wells we did not have problems with. We think by tweaking things and continuing to make some improvements, probably more so focused on the completion side, that we think the 6 to 6 plus kind of bcf wells would be more routine in that part of the acreage. Again, we are seeing the wells flatten out earlier. Like the [Fogel 5] and 6, for instance, decline rates on those are very low at this point in time. In any case to answer your question, yes.

And the history that I guess everybody in the whole play has on the wells is somewhat limited to date, what do you see is the biggest risk to the 6 to 7bcf target for the better wells?

I don't see much of a risk, because these are fairly low maintenance kind of wells, once you get them on line they don't make a lot of water, operating costs are extremely low. We don't see a lot of risk, probably the biggest risk in the whole drilling completion of the wells is on the completion side, in our opinion. There is always things that can go wrong with these kind of pressures you're pumping at, and trying to get the frac plugs, along a 4000-foot lateral under pressures are shut in 9,000 to 10,000 times, it's a hairy situation, you got to be careful.

That's probably the more tougher part of the total execution. Once you get them on line, there is not many problems.

One last quick question, that reservoir study, consortium indicated, is that specific to east Texas or is that through the play in general.

Through the play in general. They evaluate everybody's acreage position separately, and information is shared between participants, almost like this core consortium, except it's on the reservoir modeling side. It will help you on your laterals and lateral links, spacing of laterals, help as far as the frequency of how many stages you got to do.

Help us on our year end reserve process by a bunch on supporting our reserves. We think it's a huge upside just by participating in the study.

Thank you.

Next question is from Brian Corales from Smh Capital.

Couple of quick ones, in terms of the kind of second half of the year, what kind of operation activity is going on. Is it strictly non op with Chesapeake and the Granite Walsh.

Yes, that summarizes it pretty well.

Okay. In terms of the deferral of the rigs, I'm assuming that if you don't start drilling through 2009, that they all come to you in 2010?

Well, I'm not free to disclose the negotiations of those agreements. I'm not just, we have a confidentiality clause within the agreements. But I just can't answer that question, I apologize.

Let me ask another way, would the rigs be going to the Hainesville or the Bossier?

Yes. We have a few rigs committed to east Texas, we have a few rigs committed to the Chalk. One rig committed to the -- one operator rig committed to the Granite Wash. So at the end of the day when we bring them back, we have five rigs under long-term contract and plus whatever Chesapeake is doing and the Granite Wash.

In terms of the ten thousand acres. Is that all non op or part of it is operated?

Part is operated.

That's probably 2010 event before you begin operations there again?

Yes, we drilled one operated well in the first quarter, but we will not drill anything with the rig with we have committed to the play of our own until next year, yes.

One final question, in terms of gathering processing in the Granite Wash, is there enough room there for the next couple of years or something else needs to get built?

We think for right now we are okay. We are sort of piggy-backing in Chesapeake's effort. In doing that almost all of our gas -- a lot of our gas goes in to Chesapeake and some of the gas we move ourself. For right now we are okay. For long-term if it is play, this play has a lot of upside. There will have to be some take away issues resolved, but for the time being and for the next year or two we are in good shape.

Thanks, guys.

Thank you.

The next question is from Irene Haas with Canaccord Adams.

Just a question on the Marcellus. I'm understanding that probably Hainesville would move quite a bit faster due to the infrastructure situation. How would you attack Marcellus, understanding that you've got a pretty full plate, too. When would we expect for you to get drilling in a more intense manner, 2010 or 2011 event? How would you choose to tackle this large play. Where would you zoom in on first?

Irene, what we are going to try to do with the one well with the one well we plan to get drilled, in all likelihood will be up in the northern part of the acreage. So the intent would be to drill it vertically. Up in northern PA, it appears that vertical Marcellus is economically working. It only leaves the horizontal drilling being economical, too But from a cost exposure standpoint, early on limit it to vertical and see how it does. We would go ahead and complete it and probably do long-term test, back pressure test and then feel out what it's going to take for us to get i to an active development program in the pipelines associated with that.

I would assume if we had a positive test on the first well, that we would drill additional test wells on that acreage in 2010. Simultaneously start the pipeline effort and find a home to get the gas out of there, which there are a few alternatives we located.

Thank you.

The next question is from Richard Tullis with Capital One.

Good afternoon. Baird, looking at the Hainesville, I know from your presentation you got the tight curve the well cost at $7 million for a typical well. What's been the cost of the most recent wells, and what are you looking at going forward as a possibility there?

Last two wells we drilled since we got them done in such a short period of time, we think we can drill the last two wells, assuming we stick with the typical 8-stage frac job. . There is consideration that since we done such a great job on the drilling side, maybe take more money and increase the number of frac stages on the last couple of wells to test our theory.

To answer your question, we think if we stuck with the 8 stages based on where we are to date on the last two wells we drilled and with the overall cost coming down, we think we get these things routinely done between $6.5 million to $7 million.

Okay. What did you drill the last two for.

Right now we got a little over $5 million into them waiting on completion, so you can do the math. Our completion job typically costs on a 8-stage about $1.5 million, $1.6 million.

Okay. When you look at your total acreage position with exposure to Hainesville, I guess it's about 61,000 or so net, how do you split it out between the northern and southern acreage the way you were referring to it earlier?

Well in general, based on today's prices, let me say that, that's important, probably 56% of our acreage, at $4.50 flat gas, NYMEX gas price. If you ratchet that up to, say, $7, a lot of the northern acreage becomes economical. If you let it go to $7, probably additional 20% to 30% becomes economical, probably average reserves of the wells up to the north are probably in the 3 to 4bcf range. Which means then, we got probably, and again, this is not an exact science at this time, take it for what it's worth. But there's probably 20% of our acreage left that you probably wouldn't drill at all under any scenario.

Wouldn't drill for the Hainesville?

For the Hainesville yes, sir. Other reasons to drill.

So of your total 60,000, 20% you would never drill for Hainesville at the current well costs.

Of the lower Bossier. But as I pointed out and Jim pointed out, we are finding other things on the core we took that could make some of these things perspective. Like the Upper Bossier where free gas is there. The [smack over] line which has some porosity and perm associated with it, we completed with vertical drilling a few years ago, has sustained rates, that we think horizontal drilling may have an application to it and an upside.

As you go to the north, the lower Cotton Valley is the most contiguous part of the Cotton Valley called the Tailor, and there have been folks drilled horizontally up there, that have made sense out of it, and there may be some reasons to do that. That's what's good about east Texas, there is multiple things to do.

So of the remaining 80% of the acreage, $7 gas, long-term, how much of that do you think is perspective for Hainesville Bossier?

All of it.

$7 gas, 80% of it is all perspective.

Okay. What kind of rates of return would you get for the 3 to 4b wells in the north?

Need a $7 gas price, but you would still end up with a 15% to 20% after tax.

Okay. How much of the acreage is in the north?

Well, if you take 56% of the acreage in the south, then the other 20% to 30% would be in the north. Roughly 40% of our acreage is either nonproductive or not perspective or within the lower reserve number.

Okay. For the wells that have been on line for several months, Lower Bossier, what sort of OpEx costs do you see just on those wells?

Our OpEx costs are about $0.25 to $0.30. Pretty low compared to the Cotton Valley.

Mainly due to lack of any necessary compression?

No compression, low swd costs. All the good things.

Okay. Then just finally, any potential for change in the current structure? Monetized, all or part of PVG or anything like that?

Certainly, if we were going to do that I wouldn't say we were. But we think about everything, whether monetize all or part of PVG or any other way of raising capital, we are well aware of while we are not in bad shape from liquidity standpoint right now. We are aware gas prices are not very resilient. So we are looking at a lot of things. There is no specific that I could report on right now.

Okay. All right, well thank you, that's all from me.

Thank you.

The next question is from Bradley Keiths with Bradley Keiths Investment Service.

Good afternoon, thank you. From the wells that you see that Petrohawk has in Hainesville and Louisiana and Chesapeake indicated in the conference call that they think the Louisiana side is better. But I also heard commentaries that people feel the Texas side is as good geologically ,but doesn't have the open flow or initial production rates yet that match Louisiana. So based on that, what is your perspective about the Texas side of Hainesville versus Louisiana side, and how to best take advantage of the Texas side where you're primarily centered?

Brad, clearly there is something a hell of a lot different where Petrohawk is drilling these 20 million to 25 million a day wells as compared to east Texas. Within that overall Elm Grove footprint, there is clearly something geologically different. There is a structure there. It's a little bit deeper, the pressures are higher. We think there is probably a higher silica content which adds to the porosity and perm. Plus because of the structure, there could be natural fractures that enhance the perm itself.

There is clearly something a lot different about Elm Grove compared to east Texas. And even if we improve things in east Texas, I don't think we could get to a rate that some guys experienced in the overall Elm Grove footprint. Now having said that, there are areas in north Louisiana that are in the same categories as east Texas, like northern [Catocan] or western part of the northern Louisiana fairway that approach the Texas, Louisiana line, I think they are in the same category. The Elm Grove footprint area is a lot different, in my opinion geologically and everything else is sort of on the same playing field geologically.

Okay. Because I know I think it was your first major well on the Texas side, had a mid teens or something like that initial production rate. Do you expect to duplicate that on others or did you feel that was a logical area?

It was 8.8 was our IP on that, we felt we could have opened that up at the time and got a fairly short-term high IP rate. That's one thing to remember, people sort of control these rates depending on how they decide to produce these wells early on. We sort of babied this things. I do think we can get our rates up. But the question is how many frac stages can you afford to pump away to justify the incremental cost to pump the additional stages away. That's the exercise that we are going through now on trying to understand that relationship.

So we could pump more stages away and see higher rates, higher IP's in east Texas. As far as our acreage, but we elected no to do that for a few reasons, but for that reason I don't think geologically there is a heck of a lot of difference between east Texas and a lot of what is going on in north Louisiana, other than the Elm Grove immediate area.

You are trying to maximize your rate of return by balancing the number of frac jobs versus the cost and return you expect to get from it.

That's exactly right.

Next question is from David Snow with Energy Equities.

Did you say that in a year going non-consent with Chesapeake on the Granite Wash?

No.

Okay.

Said exactly the opposite.

Okay. I guess you heard them say that was the highest rate of return project in the whole country.

Did I say that.

Yes, yesterday.

At least we are consistent then, right?

Absolutely. It sure does confirm what you are saying.

We are confirming what they are saying.

All right. Okay. I will go along with that, thank you very much. Appreciate it.

Next question is from Scott Hanold.

You made a comment on the Granite Wash indicating there is running room in that play. With your 10,000 acres in that play, how much room is there to expand that position, and just in terms of the play as a whole, is it pretty under developed, is there a lot to do and pick out there yet?

We are not throwing the cards out on the table. To answer your question there is running room in the Granite Wash, new things to do there, yes, yes, yes.

Stay tuned.

Yes.

Stay tuned.

Okay.

There are no further questions. I would like to turn it back to management for closing remarks.

Thank you for all of you that participated and listened in on the phone and on the internet. I want to thank the people who asked questions, because of the level of interest that you demonstrate helps us to tell our story. So we appreciate your asking those questions. We look forward to talking to you again at the end of the next quarter. Thank you.

This concludes the teleconference, you may disconnect your lines. Thank you for your participation.