Ranger Oil Corp (ROCC) 2006 Q3 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to the Penn Virginia Corporation third quarter 2006 conference call.

I would now like to introduce your host, Mr. Jim Dearlove, President and Chief Executive Officer of Penn Virginia Corporation.

Thank you, Mr. Dearlove, you may begin.

Thank you, operator, and good afternoon. It's a pleasure to be here to discuss the third quarter of Penn Virginia's results with you. I'm joined today by Frank Pici, who is our CFO, and here in Philadelphia, Baird Whitehead, is the President of our Oil and Gas Company, Nancy Snyder who is our General Counsel. Our treasurer happens to be here as well, Steve Hartman. A name that is new to you but you'll undoubtedly get to know over time is Jim Dean who has recently joined us as a -- the Director of Investor Relations for both Penn Virginia and Penn Virginia Resource Partners our MLP. Remote from this -- this particular office but on the phone is Keith Horton who runs our Coal Operations for the MLP and Ron Page who runs our midstream business, and Forrest McNair who is the Controller of all of our Sundry companies.

I won't read you the release but I'll read -- try to follow it in form -- format, anyway, and then I'm going to ask Baird to help me out taking you through oil and gas operations, and Frank to talk about some of the derivative and capital issues that are raised in the release.

As you can see and can read, the third quarter net income was $22.9 million, a little over the 20 million that we had in the third quarter of '05. Operating income and operation -- operating cash flow was down slightly over -- compared to the third quarter of last year, 44.6 million versus 46.8 for the operating income and 66.6, 67.3 for the cash flow from operations, so down slightly. For the nine months we were pretty much ahead of last year, 65 million of net income versus 35, $143 million of operating income versus 101, $198 million of cash flow versus 164. If you look in the segment information that's in the release what you'll see is kind of what's going on in the third quarter. For the nine months, we were pretty ahead of last year, 65 million of net income versus 35. $143 million of operating income versus 101. $198 million of cash flow versus 164. What -- what -- if you look in the segment information that's in the -- in the release, what you'll see is what's going on.

In the third quarter, the oil and gas company, despite an increase in production of about 10% quarter to quarter, was looking at realized prices that were down about 17% from 8 -- 35 an m ast year to 689 this year. So that -- that was really what affected the performance '06 third quarter to '05 third quarter, even though the midstream and coal segments of the Master Limited Partnership had good quarters and had terrific first nine month's results. Again, looking at the segment information for the oil and gas company, production was up about 9% for the nine months, and while prices were down, they weren't down nearly as dramatically as they were in the third quarter, so we had a positive contributions from both coal, midstream, and oil and gas, and that is why the third -- the nine-month numbers are running ahead of last year.

Before I talk about operations, I just want to mention something about the MLP. We increased our distributions. Effective November the 14th of this month they'll go to $1.60 on an annualized basis, or $0.40 a quarter. It's becoming more and more important to Penn Virginia that the performance of PVR this year, 2006, we would expect we will receive about $27 million of cash from PVR. Next year, 2007, if we didn't raise the distributions at all, because of the effects of what's called incentive distribution rights, and I don't want to get too technical here, we would expect to receive about $40 million from PVR. So it's getting to be real money.

And one last thing on PVR, and in short, talking about its increases in distribution. Since the inception of the M LP five years ago, almost to the day, we've increased those distributions every year, and the compound average growth rate of increase was 9.9%. And finally, and then that's it on this, with the payment of this distribution on the 14th, we will officially be out of subordination, which merely -- there was very little risk that we were going to get caught up in that anyway, but now that risk has completely disappeared.

So with that, Baird, I'll ask to you take us through the oil and gas segment, if you would.

Okay. Thanks, Jim.

I wanted to go ahead and go through each one of our play types we're involved with right now and bring everybody up to speed. We didn't mention in New Albany in our press release but really nothing has changed since the last quarter. We drilled two wells to date. We have one well that's completed. It's under a long-term test. It's making a little bit of gas and about 70 barrels water a day. Before the end of the year, we plan on drilling one additional well structurally deeper and taking a core and analyzing gas con -- content of that core before we proceed.

In the Williston Basin to date we have plugged all three wells we had drilled up there and both -- one of which was the Bakken Dolomite, the other two were Ratcliffe Wells. The Bakken well got caught up in some faulting that appeared to get us to some shallow water which we could not remediate. The other two -- the Ratcliffe wells just made 100% of water.

Clearly, it's disappointing considering what's happened, but we've got 80,000 acres up there, 20,000 acres in Dunn County we have yet to drill a well. We think there are legitimate prospects remaining up there and we will continue to pursue with that project in 2007.

So far we have not talked a lot about this, but you will start hearing more of it here, that being the Fayetteville Shale. To date we have about 13,000 acres in that play. We just spudded our first horizontal well in which we have about a 70% working interest, and we plan on drilling two before year end. We have also participated in two wells with Southwestern, with some fairly low working interest. The first of which is drilling horizontally. So, you're going to hear more about this play as time goes on.

The Selma Chalk, as in our press release, that is an asset we continue to grow. We averaged 16.7 million a day in the third quarter of this year as compared to 15.3 third quarter last year. For a little history, the Selma Chalk is an extremely tight reservoir that we currently drill on 20-acre spacing. Based on some extensive modeling that we had done there is some indications that that stuff really needs to be drilled on 10-acre spacing, and we will be doing that in the fourth quarter of this year.

One method is to drill a horizontal well in which we are currently drilling. We'll drill about a 1400-foot lateral on that first well. We plan on drilling two of these before the end of the year, one of which in Gwinville, one of which in Baxterville. The other method is, we're going go ahead a just drill five 10-acre vertical wells and compare the results of the vertical program versus the horizontal program. But, if the 10-acre spacing idea works as you would expect, it's going to add a lot of locations in our inventory as time goes on.

The horizontal CBM project, as mentioned in the press release, our ramp-up in production has been slowed down because there's some water disposal issues that really we have been facing since the beginning of this year. We are aggressively remediating those -- those problems with three ways. One of which is disposal well. The other two of which being a land application, and MPDES permits. Right now we have non-pattern shut-in because of the water, but as the rest of this year goes on, in first quarter of '07, and as we get these solutions in place, we will be able to continue to turn these wells back in line, and we should see an increase in production beginning the first half of next year.

We continue to be optimistic with this play in spite of our slowdown this year. We have a motivated partner to drill wells. We have three rigs working. We expect to add at least a fourth rig in 2007 and maybe more depending on permits and water disposal, but in any case, we have all our transportation issues resolved and really once we get this last piece of the puzzle out of the way being the water disposal, we'll be ready to actively start drilling wells again.

Crow Creek was the acquisition we made in the second quarter. We're busy right now on those assets. We have two rigs working drill and the horizontal PBM wells, and we spud the first Granite Wash well in Washita County, Oklahoma. The horizontal CBM program has worked very well to date. In fact, we just turned a well in line making about a million a day in which we have about 60% working interest that cost about $0.5 million plus or minus to drill and complete. So the economics of those kind of wells are no-brainers.

South Louisiana has been an active year for us. We will drill nine wells before the end of the year. We have drilled five wells to date, three of which have been successful, two dry holes, and are currently drilling three more. Our Bayou Postillion Prospect which was in the press release has been very successful. We recently turned in a line of [indiscernible], in the press release it was at10 million a day, production has actually ramped up on that to 14 million a day.

There have been four wells drilled in that Prospect to date between late last year and this year. Out of the three out of the four wells producing were making 27 million a day gross, 4.7 million a day net. The fourth well is waiting on completion, and a fifth well is currently drilling. So that stuff is working out very well.

If you look at that time overall fault complex which could have anywhere to three different -- three to four different fault blocks, total Prospect could have up to 100 B's in which we would have 15 to 20 B's net to Penn Virginia. We're currently drilling on the Floyd Prospect which has an unrisked reserve potential of 50 B's. We just spudded the Mystic Bayou Prospect with Brigham in which we have a 30% working interest and what has a reserve potential up to 13 bcf. And we will soon spud what we refer to as our [Knockendo] Prospect in our Bayou Carlin area. We'll have a 20% interest in that, Hunt will be the operator. That's a prospect that has a 14 to 31 bcf potential.

And lastly, I wanted to mention the Cotton Valley which is very active right now, is getting a lot of hype. You have seen the results of some of horizontal drilling between Devon and most recently I saw one from XTO. Right now we have three rigs drilling within the AMI with GMX. We've had up to five rigs drilling this year. The fourth rig is drilling now for GMX on a shared agreement that we have. And the fifth rig was recently released in anticipation of us getting the Grey Wolf rig which should be here probably by the end of this month.

We'll probably end up drilling anywhere from 50 to 55 gross wells before the end of the year. Production in the third quarter was 12.8 million a day, it was a 103% increase from third quarter '05, and a 20% increase from the second quarter of '06. And right now our estimated Cotton Valley production is about 15.5 million a day. We did drill a 2100-foot lateral and a lower Bossier test which is a zone about 900 feet below the Cotton Valley. It is a shale. It's a limey shale. We put a huge acid job on it. We didn't -- or we're not able to get this thing completed as we had designed it for.

We actually had to treat three different intervals simultaneously trying to use some diverters to get into all three zones, but right now that well is cleaning up. We've got roughly 14,000 barrels of acid to get back. It's making about 600 mcf a day and we think over time as we clean it up it it's going to improve. We know the reservoir is tight. We also think it's suitable for horizontal drilling, but it is a huge resource in which we're going to continue to spend some time on.

In fact, we think for ever -- for every 640 acres there's about 100 bcf of resource within this Lower Bossier Zone by itself. So, I can't tell you where this well is going to end up rate-wise, but I know that we will probably drill another horizontal well in it first quarter of '07, and like GMX announced, we will be spudding ago horizontal Cotton Valley well in the Taylor part of the Cotton Valley before the end this month.

It's doubtful whether we'll have this thing TD'ed before the end of this year, but this is something we're excited, of course about because of the results and we think it is very suitable for horizontal drilling. So you can see we're extremely busy right now with all our activity and these different play types.

Thanks a lot, Baird. I'll sum up PVR.

Thanks, Jim.

Great. I won't -- I'll sum up PVR. I won't go into that level of detail. Clearly, people can ask questions. Also, there's a website for PVR, and the conference call we had a couple hours ago is up on there. You can get a little bit a more color or background there.

But basically PVR had a good third quarter. It had a record level of net income, operating income was $30 million versus 22.5 last year, and the important measure in MLP distributable cash flow was up a few percent to 25.2 million from 24.6 last year. Likewise, for the first nine months, the Partnership enjoyed a very solid nine months. $75 million of distributable cash flow up from 63. 55 million of operating income up from 45, net income at 53 up from 37.

The increases particularly in distributable cash flow and operating income were due to the relatively high processing margins. In fact, very high processing margins, or frac spreads, if you want that word, that were experienced by PVR midstream and also driven by higher coal royalty revenues.

Coal royalty revenues in turn driven by two things. Namely, production was up a little bit for the quarter. It was up to 8.9 million tons from 8.5, and realized prices were up I believe to about $3.03 from about $2.67. So both of those pieces of the MLP did quite well. In fact, the operating income from coal alone was 18 -- almost $19 million, up from about 16.5, or 13% increase.

Revenues were up to 30 million from 26, which is a 15% increase and it represented a record -- records are records, but what really is happening here is you're seeing the results, I think of, the acquisition program that we've been fairly active in, particularly in 2005 and 6.

Likewise, moving over to the natural gas midstream, operating income at 11 million for the quarter versus about 6 million a quarter, the same quarter last year, inlet volumes at almost 160 million a day up from 126. As I said, frac spreads earlier in the quarter were probably at all-time highs, and they're still very -- I don't like the word robust, but I'll use it. They're very robust right now.

I mentioned the distribution increase. So, I'll be happy to answer any questions on PVR, but that's probably all I'm going to say about it for the moment. I might ask Frank Pici to talk a little bit about capital resources, the derivative impacts and then maybe kind of flip over and just run through guidance, quickly, Frank.

Okay, sure. Thanks, Jim. Good afternoon, everybody.

I guess, a couple things starting with our capital resources. On PVA, we had $180 million borrowed on our revolving credit facility. That was a $200 million facility, and as part of our mid-year redetermination on that facility, we have decided to increase it as well to 300 million. That was just -- just in part -- credit agreement was just amended yesterday, in fact, to effect that increase. We've got an increased borrowing base as well that we're not taking full advantage of, but the point of that being that we believe we have plenty of dry powder to support the opportunity set that Baird talked to you about.

And, by the way, we're in the process of compiling our 2007 capital budget and out-year plan as well. We'll speak to you more on that as we get closer to year end. On PVR, and I'll flip back and forth a bit, we had more debt outstanding there at almost $327 million, but that's still well within our needed -- necessary coverage ratios and limits on those relative facilities, which are, as I think you all know, are non-recourse to PVA but are consolidated in.

We do hedging on both PVA and PVR midstream on our oil and gas hedging we've got about 40% of our fourth quarter production hedged. That drops down to about 20% of '07 and about 60% of '08 based on current run rates. We are in the process now of looking at those positions and possibly adding to them. We are currently modeling that and trying to come up with the right -- right combination of positions to protect our capital budget more than anything else, as we go into '07.

On the midstream side we are -- we are also hedged about 65% of Q4 midstream production, dropping to 30% in '07 and '08. We're also developing a model there which is a little different. It's more of a cash flow at risk type model there that we are working on through Steve Hartman and his group to come up with the optimal mix of positions as we go out into time and what level to hedge at there.

As you probably know, we've gone mark to market on our hedge accounting. That has sort of introduced some different kind of volatility. We had volatility even before that, but what we're doing now is we think it's -- hopefully a little simpler to follow in that what we show in our income statement is the change in the mark to market value of the open positions, and in the third quarter of '06 we had -- we had gains in both the oil and gas and midstream segments from those positions totaling about $18 million. About 12 or 11.5 from the oil and gas side and about -- a little over 6 on the midstream side.

If you look at that from the cash position, cash settlements during the quarter, we actually had some receipts or collections on our derivative position during the third quarter in the oil and gas segment of about a little over $3 million. We continued to pay out on our midstream positions, which are older positions, older initiated positions, of about $7 million. So -- and those things I think are reflected as you go through the cash flow statements as well. So what you'll find is from an income statement standpoint, it's not always the easiest thing to understand, but you would find, as you dig through this, that the price realizations on the oil and gas side were increased in the third quarter as a result of the hedging we did.

Looking forward, if you get into the guidance section, and there's a table in the back of the press release on guidance, I guess I would just try to point you to any changes. And I would characterize the guidance on the whole as being sort of just a tightening of the ranges. We now have three-quarters of actuals in there, so our full-year guidance, of course, is just including the fourth quarter. When you look at things like production, oil and gas production, you'll see that we've kept the top of the production estimate range at 32 B's. We have simply increased the bottom of that range since we have less variability likely at this point.

When you get into things like direct expenses on oil and gas, we have increased that a bit, about $1 million on midpoint. That's really a reflection of the higher operating expenses we saw during the third quarter for some work-over costs and water disposal related costs. The other components of oil and gas related expenses are pretty much, like I said, a tightening of ranges. We did have an increase on exploration expense as well in our guidance and that's really a function of our -- of both our third quarter reported numbers and our fairly aggressive fourth quarter drilling plan.

When you get into capital expenditures for the oil and gas segment, you'll see not much change at all from prior guidance in total. We have shifted some dollars around, primarily from our sort of gathering facilities line up to exploratory drilling. We've got a little more -- some of our drilling is being characterized by definition as exploratory so we had to increase our guidance there on the CapEx side. But in total, the capital expenditures estimates for oil and gas are pretty close to what they were last quarter.

When you flip down to the coal segment, once again it's primarily a tightening of the range. We do expect to see a slightly lower royalty per ton realization in the fourth quarter, and that's really just a -- because of the mix of where our coal in central Appalachia is being mined from. When you the get into our capital expenditures, not much change there.

Getting into the natural gas midstream segment, really the only significant change there would be in the capital expenditure section, some of the things we characterized as expansion capital we've moved into maintenance capital, and that's just to have an accurate calculation of distributable cash flow at the partnership level. We have to make sure they're defined the right way.

Otherwise, I'd say the rest of the guidance is pretty similar to what we've had last time. We did have a debt increase in PVR quarter to quarter, just as a result of funding the Huff Creek acquisition we made in the coal segment, but otherwise our full-year guidance on the debt side and interest side are pretty similar to what we had told you about in the last quarter.

Thank you, Frank.

Sure.

So that pretty much wraps it up. I might say by way of summary that as could you tell from Baird's report, and you couldn't tell as much from what I said about the MLP, but we're very active this year, and part of that activity is to position oneself to keep going into the future, hence the Crow Creek acquisition, for example, has given us a lot of running room in basins where we didn't used to have a presence. The Huff Creek acquisition of coal added an important resource of high quality coal in West Virginia. The Transwestern acquisition with midstream that we completed this year as well, while not large in size, is quite important in terms of consolidating our position around our most important plant, the Beaver Plant. So, it's not -- it's activity, but it's also positioning, to continue to grow the Company and move forward.

So with that, operator, I'd be very happy to try to answer any questions.

Thank you.

[OPERATOR INSTRUCTIONS]

Our first question is from Ray Deacon with BMO Capital Markets. Please state your question.

Yes. Hey, had a question for Baird, if there was any new information on the horizontal shale activities that you had going on I think a quarter ago, if there's any new news out there.

Ray, we're not going to get our shale wells drilled this year because of the inability to be able to secure a rig. We are going to plan on being active in '07 tentatively, so that as we can tie up a rig for the bulk of the year so as we won't after the problem of trying to pick up one rig for one well here, one well there. So we're not going to get our program drilled this year in the shale but we're going to be busy next year.

Okay. Got it.

The next question is from Dan Morrison with Aperion Group. Please state your question.

Another question for Baird. On your Bossier horizontal, I know it's still early and stuff, but what kind of flow-back rates have you seen on the load recovery even?

Dan, in order to accelerate the flow-back raters, we've actually installed some gaseous valves in this thing here a few days ago. We're making anywhere from 150 to 200 barrels of water a day right now with that gas lift. That was going to -- we're able to get it quicker, of course, get it cleaned up quicker the the than letting it flow on its own. It did it not stop flying but we thought we'd accelerate the load recovery by putting those gas valves in.

You alluded to the fact that the completion just didn't go exactly as designed. Could you elaborate a little bit more on what you had wanted to do and what you ended up having to settle for?

Tried to get the Tacker Plus system in the ground. We were drilling some slim hole. We were drilling out of a sidetracked hole. We had some crooks in it. We were unable to get those inflatable packers down through some dog legs, so in order to get the liner in the ground, plus the well was trying to flow on us, and it was of concern, so we decided to go ahead and lay those packers down, just run a three-inch flex joint liner in the hole and just based on mud luck shows and those kind of things we perforate based on those mud logs and ran some diverting agents to rot the acid job itself and try to get into all three zones.

So you didn't get an electric log on the horizontal?

We did not. But we had mud logs shows almost throughout the entire interval. We had a lot of gas in the system as we drilled, and as we drilled laterally longer, the gas in the system continued to increase to the point we had to stop.

Great. Thanks.

The next question is from Eric Hagen with First Albany Capital. Please state your question.

Question for Frank on the -- to get to a recurring number on the bottom line. With the new hedge accounting for the hedges, is it correct to say that your realized prices now will not include the effective hedges, and that in the income statement, that changes in derivatives also includes the cash settlements which we can then find in the cash flow statement, and net those two to get a non-cash charge?

Eric, it's not quite as clean as that. I will say that the realized price does not include the effect of the cash settlements on the hedges. For example, in the third quarter, the natural gas price shown on the press release is $6.89. If you included the cash we received on the hedges during the quarter that price would have been $7.23. So that cash impact -- and I think we tried to say that in the release. It will be in our 10-Q as well.

But -- so those realized prices will not include the hedging impact. When you get to the income statement, it's a little bit messier than that. But the derivative is line on the income statement is primarily just the change in the mark to market. But what you'll see is that's always a change at a point in time, so if you settle a hedge that you've mark to market in one quarter and you settle for a slightly different number, then that change or that difference is going to run through the derivatives line as well. So there's a little bit of noise there but it's primarily mark to market impact on the income statement.

Okay. Thanks. I'll give you a call off-line just to go through that a little bit more.

Then for Baird, the Lower Cotton Valley, I was a little bit confused as to the two press releases. In the first one it seemed like you were going to in terms of vertical wells, kind of just back off for now, see all the 13 wells that are drilled there perform over an extended period, and then today got the impression that you may continue to drill down to that zone. Which would be the correct impression?

Eric, we have, as you know, been drilling the deeper wells to test four different zones within that overall deeper section. We have -- I think we have 13 of these wells drilled now with various results. The Lower Bossier appears to be the most consistent that we think has the most upside because of the resource potential.

Because we did this out of a side-track hole in this first horizontal attempt, we want to go ahead and try this with a new well, use the Packer Plus System so as we can get a four to five-stage frac job along the interval, because we do think that there is a lot of potential with this Lower Bossier. More so than the other three zones. That's our opinion.

So the intent would be to shut down the vertical program through the deeper stuff and continue with the horizontal program in the Lower Bossier and, of course,the lower part of the Cotton Valley that being the Taylor Sands.

Okay. So basically you just see more up side potential from the horizontal right now than maybe from the vertical and sort of shift your capital and efforts into the horizontal, is that fair to say?

Yes. I mean, it's not going to go real fast. We want to watch this one we drilled, get the next one drilled probably the first quarter of '07 and see how it does, and get the Cotton Valley horizontal well drilled. If we get into a horizontal drilling program in general, that changes life a lot. Versus routinely just drilling vertical Cotton Valley wells you may be doing a mix of both horizontal Lower Bossier and horizontal Cotton Valley wells. It's going to take time to get all that sorted out, but that's a good problem to have.

Okay. Last question, I was in Crow Creek, the horizontal CVM well, you said it came on at 1 million a day and cost 500,000 all in. Is that going to be representative, do you think, of wells going forward? What would be a good sort of average to use, or have you established that yet?

Probably a good average, at least based on the wells that have been drilled in that play, by our predecessor and the wells we drill, probably 0.5 million a day, still good, still very good. It was on the upper end admittedly, but I'd say 0.5 million a day is probably going to be a good average.

Will that rate sort of correspond to the EUR? I mean, can we say 500 million well off 0.5 million a day, or is that -- that doesn't correlate like that?

I wouldn't make that heap of faith. Typically 0.5 million a day well is about a 500 million well.

Okay. And then Following up on that, how much acreage do you have there now total and what kind of spacing are you drilling on? Or how many net locations do you have left to drill on that?

To be honest with you, I can't remember.

All right. I'll call you off-line and get that. I just wondered. All right. Thanks, Baird.

Okay.

The next question comes from Richard Mormon with Capital One Southcoast.

Good afternoon, gentlemen, just wanted a couple quick understandings on the Cotton Valley. You mentioned you're always acquiring net acres. I was wondering if you could give us a rough idea of your current net acreage in the play.

Between a GMX-AMI and the stuff we have 100% outside of the AMI, we've got approximately 40,000-plus acres, net acres.

Okay. And on the rig count, just to understand what would be the sort of net rig counts? Because you mentioned some of them are drilling on the mixed joint venture acreage, and some on your 100%. What -- how many net rigs would you have running?

I don't -- let me see if I can answer that question. We think, of course, gross rigs, we think we have 4.5 gross -- 4.5 gross rigs. The other half rig is the one that GMX and Penn Virginia share. So we keep four rigs working, or the 4.5 rigs working between the 70% stuff that we have, the 50% stuff that we have, and the 100% stuff that we have. And rigs are sort of going back and forth all the time. So trying to answer that question, I think, is very difficult to answer.

Okay. Fair enough. And then on the Bossier, I appreciate this was extremely technically challenging to reenter a 5.5-inch well bore and obviously makes it difficult to do multi-staging. I guess one thing that popped across my mind though here, I saw in the past where EOG and the Wolfcamp play, now going out to New Mexico, had tried acid fracs without as much success and then was switching to more a traditional cross-linked gel fracs had posted a lot better results

Just wondering your take, first of all, why you wanted an acid frac in the Bossier, which correct me if I'm wrong, I thought was more of sandy formation, then secondly what your thoughts are about trying a cross-linked gel here.

Based on solubility tests, our Lower Bossier is a limey shale, extremely limey. And it is very acid soluble. The acid we get back is spent, we feel, and the fractors that we have seen based on some open-hole logs are calci field. So everything we have sees with the Lower Bossier we think is acid suitable.

We do run some sand throughout the job. It's not very much. Primarily as a diverter. Like in this job right here, I think we ran 70,000 pounds throughout the job. But that was our thinking. We have seen on the vertical wells we have drilled, the acid jobs have worked in the Lower Bossier at -- and we see lower rates as a result, but we think it the's very suitable for acid jobs.

Okay. Then I guess just your thoughts on a cross-linked gel, or something of that effect, with maybe a higher sand content. So in theory going to crack the rock more and profit more as opposed to etch it. What do you think of that?

Well right now, cross-link jobs can be slow -- very slow to clean up on a tight reservoir like this, and that would be our concern. Maybe we could assist it with CO2 or nitrogen or something, but the frac rate on this stuff is extremely high. This is not a formation that's going to take four or five or six or eight pounds per gallon because would it screen out on you. Frac rating on this Lower Bossier are anywhere from 0.95 to 1, which I know is technical, but they're high. That is extremely high. You're not going to put a lot of sand away in this stuff. So I don't think it would probably work.

Okay. No, I appreciate the great answer about 50% higher. Thank you. I do appreciate it. I think the 7-inch well will do wonders for you. So thanks.

Thank you.

The next question is from Biju Perincheril with Fortis Bank. Please state your question.

Hi. A question for Baird. Can you tell us a little bit about the drilling that you have done in the Cotton Valley in your 100% acreage, and those wells compare to the wells you drilled on the AMI acreage?

Sure, Biju.

We have drilled I think eight wells so far, seven of which have been completed. Across that acreage, which is not a lot of wells, considering we have 30,000 plus net acres up there. We have mixed results. We think, and I'm not ready to say that it's a slam dunk. We are typically seeing more water up that way, but what we are seeing, a different part of the Cotton Valley has a lot of potential, which would probably reduce our costs and make a lot of economic sense.

That's the approach that we're working on right now. We just drilled a well that looks extremely good on the open-hole logs on another part of the 100% acreage. So it's taken time to get this figured out, but we think we are getting it figured out. It is different than what we have to the south within the GMX stuff.

What's your plans going forward? Can you give us some number on wells that you plan to drill next year?

I can't remember. We're going drill some more up there. We've got some that we're actually running a pipeline to, and we'll start laying a pipeline to very soon. But we're going to continue to drill wells, and as we see positive results, we'll jump in there and drill some offsets to it. So it's a difficult question to answer. You know, a couple wells we're going to get turned in line, we should know something here probably in the first quarter of '07 as far as how they're acting, and we would have some offsets immediately that we've already got staked.

Okay. Thanks.

Thank you.

[OPERATOR INSTRUCTIONS]

The next question comes from Scott Hanold with RBC Capital Markets. Please state your question.

Good afternoon. Considering the last few wells that you drilled in the Williston Basin, and you've become very active in a lot of areas, including Fayetteville and additionally in the Cotton Valley is there going to be sort of a shift in activity as we go into '07, and sort of can you talk a little bit about where you feel comfortable spending capital next year?

Scott, this is Baird. We think that the Williston still has a lot of potential. In spite of the three dry holes, we've got 80,000 gross acres in three different prospects. One of those prospects we've not even drilled a well yet. And it's a Bakken Dolomite prospect.

So, no, we have not given up on that play, or plays. We're going to continue to drill some wells in '07 and new prospects within those overall acreage areas and continue to test the acreage, but we have not given up on that play and we think there's a lot of potential.

Scott, we're trying to -- we're in the middle of budget process, and capital budgets aren't by any means locked down yet. But I think Baird gave you an accurate answer that you try to trade off things as you well know. We want to learn about the Fayetteville Shale, for example. We want to learn about whether or not some of these Cotton Valley experiments that Baird and some of you on the call just talked about. We want to find out if the 10-acre spacing in Mississippi is going to work.

So there's a lot of that sort of positioning, I'll use that word again, going on, and based on how these things work out, you shift capital around even during the year. So even if we could give you a snapshot now, which we really can't, because budgets aren't completely in place, over the course of the year if you sort of look historically at what we have been doing the last few years as the Company is really gotten up on its feet, the oil and gas company, you'd see a lot of shifting around even within the year, because you're reactive. You try to give yourself a lot of opportunities to do some things and then react to what you find.

I know that's not helpful in building a model, but it is, in fact, the way we do it.

Scott this is Frank. One other thing. We're put -- the budget will probably be out. and last year I think we put out some news for public consumption on our budgets in mid-late December, as I recall. We'll do that again this year most likely, but the big areas, we call it our big three development areas this year, were primarily Cotton Valley, then Mississippi and Appalachia, with our HCBM up there.

With the addition of Crow Creek this summer, we've got at least one other area that we think we can develop on a fairly aggressive basis, as Baird has said with the CBM play and the [Harchroam] coal. So when you look into '07 you can probably expect a mix that doesn't look to much unlike '06 except you might see a little more concentration on Cotton Valley, perhaps, and this new area will probably have some -- a fair amount of dollars allocated to it as well.

Okay. And in Williston, are you guys operating that at all? Or is that going to be all non-op for you guys?

The third area, the 20,000 acres, we have not drilled a well in yet. We will be the operator on that.

Okay. Thank you.

Thank you.

Our next question is from Dan Morrison with Aperion Group. Please state your question.

Kind of follow up on the production guidance. Even though you tightened up the range a little bit that's still a pretty good spread on fourth quarter numbers. Was wondering if you could give a little color into the things -- what are the things that push it towards the upper end versus the lower end?

Well, Dan, I'll -- this is Frank. I'll take a shot, and, Baird, please jump in whenever you want. But I guess, some of the things that could come into play is the level at which the -- some of the south Louisiana stuff stays on line at, Baird?

That's correct.

The additional things that the ramp up -- we'd expect to see some kind of an increase in our Cotton Valley play as well, and there's always some variability to those ramp-ups, Dan, as you know, so we left ourselves a little bit of room there as well.

But in terms of the big areas that we'd expect to grow, it it will probably be in -- or at least vary a lot, be in those areas to a lesser extent to the extent we get the HCBM water disposal issues, the faster we get those issued, resolved, the faster production will ramp up there from where we are today. And I think that's probably the bulk of them. There's always a little bit of movement both ways when you get to the other field.

Quick follow-up to the Cotton Valley as part of that, just being one of the variables there. Has the recent environment freed up or simplified the logistics on the completion phase at all with more availability or are things still extremely tight?

Well, we're drilling so many wells, and we're still active, the service companies, the pumping companies primarily -- they're taking care of us very well. They're making a lot of revenue off Penn Virginia up in east Texas, it's concentrated in a fairly concise area, so they like working for Penn Virginia, and we have not had problems on that end.

Good. Thank you.

Thank you.

I'm showing no further questions in queue. Do you have any closing comments?

No, other than to saying a gain, appreciate the interest that people show in the Company, and we're looking forward to a good quarter in the fourth quarter, and we'll talk to you in three months. Thank you.

Thank you. This concludes today's teleconference. Thank you for your participation.