Ranger Oil Corp (ROCC) 2008 Q3 法說會逐字稿

Greetings and welcome to the Penn Virginia Corporation third quarter financial results conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (OPERATOR INSTRUCTIONS) As a reminder this conference is being with recorded. It is now my pleasure to introduce your host, Mr. Jim Dearlove, President and CEO.

Thank you Operator, and good afternoon. I'm joined on this call by a number of people. Just going sort of clockwise here, Baird Whitehead who runs our oil and gas Company; Frank Pici who is our CFO; Nancy Snyder, I'll get that right, Nancy Snyder who is our Chief Administrative Officer, they're with me here in Radnor; Forrest McNair, our Controller; and Keith Horton who runs our coal segment is in Kingsport, Tennessee.

What I'll do as I normally do, is to follow the highlights of the press release. I'd remind you that in the press release we tell you there are forward-looking statements and we will probably make some of those today and caution you that they are just that. And also, I would caution you that I will not read every word, nor every number that's in this report so I would encourage you to read this report. I'm going to make very short reference to both PVR and PVG, the MLPs with which we're associated. Their reports are on our website and their conference was recorded about two hours ago and is also, if not available right now will be available shortly.

With that, let me walk through the release of yesterday, November the 5th, for PVA. We had a very good quarter in terms of production, a record level of production, 11.7 Bcfe or about 127 million a day. This is a year-over-year third quarter to third quarter growth rate of 5%. It's about 2% higher than it was in the second quarter of 2008.

Operating income was $122 million, that happened to also be a record, well above the roughly $52 million we had in the third quarter of 2007 and most of that increase -- and we're talking about PVA now, not just the oil and gas portion of it. Most of that increase was due to the oil and gas segment and an awful lot of that increase was due to an increase in prices, reminding you now that we're talking about the third quarter, not the fourth, where we are now. And in that third quarter, especially early in the quarter, we had very high gas and oil prices as well as natural gas liquids prices. We also had an increase in production as I just mentioned. We also experienced an increase in the operating income from our MLP affiliates, the Coal Company was up about 48% year-over-year and actually the Midstream segment was down slightly, due the Hurricane Ike down about 2%. But overall, PVR was up so those both contributed to the operating income that we reported at the PVA level.

Operating cash flow, a non-GAAP measure, was $97.5 million in this quarter, compared to about $79 million in the third quarter last year, most of that due to the changes in operating income, offset by the cash to settle some derivatives. Adjusted net income, also a non-GAAP measure, but the reason we use it is it excludes the non-cash changes in derivatives fair value. That was about $46 million as compared to about 18 million or $19 million in the third quarter of 2007 and again, same reasons that applied in the operating cash flow line. Net income, which is a measure and an awful lot of people look at EPS, I understand it, I don't know how critical that measure truly is but nonetheless for us we had a very good quarter, $123.7 million, net income, compared to only 17 in the third quarter of 2007. This was due to, an awful lot of it due, though, to a large increase in derivative income, that's a non-cash change in the value of the unrealized derivative positions we had but it's also due to the higher operating net income that I just spoke about, offset by some increase in taxes and minority interest.

The oil and gas segment I'm going to let Baird do most of the talking about. Let me just sort of lead with some of the things that are in this release. We mentioned our quarterly production growth year-over-year and quarter-over-quarter. CapEx was $236 million, of which 152 was on drilling and completion. That's a lower percentage than we normally would have. Usually most of our CapEx is drilling and completing but you'll notice here some lease acquisition costs, in particular, of about $70 million which is sort of an unusual event. But we were bulking up in the Haynesville primarily in the third quarter.

Guidance for the full year, which Frank Pici will be talking to later on, but is 46.5 to 47.5 Bcfe and we -- if we hit the midpoint of that guidance we would end the year about 15% production increase over what we were in 2007. We reaffirmed as the release tells you our full year cash operating expense guidance as well as our CapEx guidance. And with that, I think Baird, what I'll do is ask you to take us through the regions.

All right. Thanks, Jim. I'm going to go through each one of the areas and let you know what's going on and of course spend a lot of time on the lower Bossier. So I'll begin with East Texas.

Right now, as was in our press release, we have four rigs drilling lower Bossier, horizontal shale wells. We have three rigs currently drilling Cotton Valley wells. Two of those three rigs will be released here, probably in the next week or two. After they finish up on the wells they're on. And a third Cotton Valley rig we're actually moving over to start drilling Bossier well. So by the end of the year, mid- to late November, we're going to have five rigs drilling lower Bossier wells with no future plans, at least in the short-term, to be drilling any Cotton Valley wells.

To go through the five wells we have drilled to date, the Bossier wells we drilled to date, the Fogle 5 which is a discovery well, it's still producing about 2 million a day, and 10 million to 15 million barrels of oil a day. We reported in the press release ultimate reserves of this well of anywhere from 6 to 8 Bcf. At least based on how this thing is acting I think there's a strong case to be made that it could be as high as 10 Bcf because of the production profile this well has. It has produced 460 million in the past 143 days, for 3.2 million a day, which I realize is less than some of the other wells have been reported at in the play, but this well is acting a lot different. I'm not saying it's going to -- every well we drill is going to act the same as a Fogle well.

When we got into this play, we expected hyperbolic design as any of these resource plays produce like but we expected what they refer to as an N factor be on the lower side, which is the exponent that describes the shape of the curve. What we're seeing, we're actually seeing a much higher N factor which means you see a higher initial decline rate but the well actually flattens out in a shorter period of time. In fact, that's what we're seeing in this Fogle one. I've seen this happen before in some of these other resource plays, the Davonia shale back East typically has some very high N factors. But in any case, the current decline rate, (inaudible) decline rate of this well right now is about 30% and based on how this thing is flattening out, we think that it's very easily to forecast it could be north of an 8 Bcf kind of well. Again, I don't know if this is going to be the typical type curve for a Haynesville well. I'm sure you're going to have some different type curves for different areas of the play. You're going to have some sweet spots in this play in general. They're going to have different type curves. But in general right now this is how the Fogle well is acting.

The Gibson well, which was about a two mile offset to the Fogle, we did announce in our press release it was making 3.5 million a day from about 2800 pounds, we treated with a little over a million tons of sand over seven stages and we have it cut back. We have intentionally on the next couple wells have decided to bring these wells on at much more restricted rates. The reason being, is we didn't see a lot of water recovery on the Fogle well. I can't exactly explain that. But the last couple wells we are bringing back at restricted rates, that being the Gibson and the McKenzie well, are cleaning up a lot better and we're seeing fluid recoveries much higher at this point, at the point of time in their productive life.

The McKenzie well, which is a 20-mile offset to the Fogle which is up in the northernmost part of our acreage of course is a key well. It has been turned in line. It's still making 700 to 800 barrels a day of frac fluids. We've only recovered about 10% of our frac fluids. But it is bringing back fluid at very good rates. It's probably not appropriate for me to say what it's producing at this time since it has only been on line now for a few weeks but it's something we'll talk more about in the fourth quarter.

The Brian well which was also a two mile offset in a different direction of course from the Fogle well, we had a mechanical problem when we were fracing that well, the casing parted. We have made some progress in getting the casing put back together. So we think we'll get that well back on and get it flowing back. I doubt if we're going to complete the last two stages of the frac job. The plan is right now is to get this thing put back together and just start flowing and cleaning it up and come back and treat the next two zones at some point in time. The Fogle 6 has been drilled and we're currently completing that well.

So that's everything I know as far as the five wells we have drilled today. As I said, we have four rigs currently drilling in that play. We're drilling laterally as we speak in the Penny Jones 8H which is also up in 100% acreage up to the North. The Gail Fur, 11H, which is 100% well in the Eastern part of our acreage. The Steeg 1H which is up in our 100% acreage to the north and the Fogle 7H which of course by name is also a development well down in the overall Fogle area. It is our tentative plan that we're going to keep five rigs drilling, both on our 100% acreage and our GMX acreage in the Haynesville going forward. We have made a few operational changes on Haynesville because of the casing part that we had in the Brian well.

We started running 4.5 casing all the way back to the surface which can stand much higher treating pressures. We are actually landing the lateral now in the upper portion of the Haynesville where as before we were landing it in the bottom third in the organic part of the Haynesville. The reason we're doing that is because the upper part is more of a reservoir type rock, it having more of a salacious content. We're improving our -- the type of bits we're using to drill these laterals and have increased penetration rates as a result. And in going forward, I think you're going to see us start increasing the number of stages we do and probably backing off on the treatment size per stage but we think it's important to probably go ahead and place these treatments along the lateral at much shorter intervals.

Next year and I've talked about this before, the upper Bossier, we think that is a valid stand-alone play. It's right beneath the base of the Cotton Valley. We have some immediate pressure increases as we drill through this stuff and have some good gas shows so for that reason, we also think it's a reservoir that merits horizontal drilling and you will see us drill a well in that stuff sometime next year.

Switching gears to Mississippi, we continue to be very pleased with the results in our horizontal chalk program. We pointed out in our press release the average for the 90 days is about 800 Mcf a day, the average for the five wells that have produced longer than 180 days, the average for those five wells is about 650 MCF a day at that point in time. So we continue to be very impressed with the results of these wells. We still think these wells are close to 2 Bcf kind of wells, ultimately, they will make anywhere from 4.5 to 5 times that of a vertical will.

We have just moved a second rig into Gwenville. So now for the rest of the year we're going to have two rigs drilling in that play We made a lot of improvements here recently in drilling time. The initial wells of which we have drilled 12 to date, were taking us about 30 days to drill. The last two wells, we've drilled respectively in 18 and 17 days. And the intent going forward, again, is to keep two rigs drilling in this play tentatively through 2009 and the Mid-Continent, we continue to grow that area. Originally to remind you, it was primarily a horizontal Hartshorne CVM play in the Arkoma Basin. Because of horizontal drilling in our Granite Wash play now in Washita County Oklahoma, we're starting to see our production increase more significant because of the type of wells.

We did report in the press release, we drilled four wells in the third quarter. Two of those wells had rates of 10.9 million and 10.5 million accordingly, the third well which was just turned in line at the time was making about 7.2 million a day and the fourth well which we had no production information as of a week ago, that well is actually making about 9 million a day and about 820 barrels of oil a day or 14 million a day equivalent and I think if I'm not mistaken a that is the best well that's been drilled in that play to date with Chesapeake.

We think going forward we're going to be able to keep two to four rigs drilling in that play. The economics of this play are very solid because of, to a large extent because of liquid content. The other play type in the Mid-Con where we have recently become pretty busy, admittedly by operated wells is at Woodford shale. We drilled two in our second quarter. We drilled three more in the third quarter. Those three wells we drilled had 3.6, 4.6 and 2.7 million a day respectively in the first 30 day rates. We have four rigs currently drilling right now that are all onsite operated by Antera. Petroquest with working interest of anywhere from 5 to 42%. Going forward, again, I'm not as clear as our activity level was going to be in this play but I think in the short-term, we should be able to keep between ourself and and Antera and Petroquest anywhere from two to three wells.

Lastly in the Mid-Continent -- rigs, excuse me. Lastly in the Mid-Con, we have -- we will be testing our own Woodford ID in the Anadarko basin. We have a rig that we'll be moving in here in a few weeks. We put together about 40,000 net acres in that play area so we're going to be able to test our own idea.

Going to the Gulf Coast, we did announce a couple good wells that we had drilled, one of which was a Cotton land number 5 which we had about a 40% working interest in. That well is making 15 million a day and 50 barrels of oil a day. We also backed in with a 25% reversionary interest in a well -- in a prospect we actually internally generated, that is a huge well. That well has made about 17 Bcf in a little over a year. It's still making about 40.5 million a day and 750 barrels of oil a day, or about 9 million a day net for Penn Virginia. With our back end we think the ultimate on that well at this time is probably north of 40 Bcf. It's probably one of the better wells I've ever been exposed to and it does have an offset to drill, tentatively we think we'll try to get it spud sometime next year. South Louisiana, again, because it does introduce some volatility. At the end of the day, we have been very successful in projects we have participated in in south Louisiana in economic returns.

And lastly in Appalachia, the Marcellus is pointed out, we have accumulated pretty close to 40,000 net acres, part of which we have acquired our self, part of which is a result of an AMI that we have formed with a small Company in Appalachia who has a very good reputation. Right now, as we speak, we just started a 50-mile 2D shoot, up in the northern part of Pennsylvania to evaluate some part of this acreage. Our plan is of course to figure out the structural components of our acreage and pick locations accordingly. We would not expect to drill anything probably until sometime the second half of '09.

And lastly, of any significance, Devonian shale. Even though temporarily we have put this program on the back burner for market conditions and product pricing reasons, we did drill two wells in Mason county. That was the area where we were going to go ahead and start a development program. We did complete one of those two wells and that well that we did complete on a long-term test has made about 2 million a day which is very, very good for that kind of well. So the plan is right now is to take the four wells we have there and to do some long-term testing, back pressure testing, to make sure we're confident with the economics before we commit to lay a line out of there. And I think that's it, Jim.

Okay. Well, thank you, Baird. I should have said this. Much of what Baird said, certainly not all of that detail, but much of what he said is contained in release that we put out on October 29, of this year where we updated our operational stuff. You won't find most of what he said in the November 5, release. You've got to go back to that one which is also on our website, I believe.

Mostly cost and processing -- costs associated with increased compression and some processing fees in East Texas. Taxes other than income up, again, basically higher severance taxes due to higher prices. G&A is up because we've been staffing up particularly in Tulsa during 2008 in the third quarter. Exploration down a little bit, just the ups and downs of the business, DD&A up a little bit, higher depletion rates per unit of production, some increased drilling costs. There's extensive obviously financial tables in the release.

Turning to PVR or PVG for a minute and I'd ask you to recall that while we report our results on a consolidated basis, it's a frustrating thing for you and analysts or an owner or an interested party, it's frustrating for us as well but that's what we're forced to do. If you look back on pages 11 and 12 of the release, you'll see it, those numbers broken out in a non-GAAP format that gives you a better snapshot of what oil and gas is doing versus the consolidated numbers. That's not to say that PVR and PVG are not important. But the end of the day, since the companies are so rolled off from each other financially, really the important thing to me, when I wear only my PVA hat, is how much cash do we get from PVG. And in that respect, we had a very -- we had an increase announced by PVG to $0.37 a unit, which is -- I don't have that particular note sitting right in front of me, but is 4 or 5% over what it was last quarter and 27% over what it was a year ago. So PVG has performed very, very well in the third quarter and we are the benefit of that cash flow. Just to remind you, we own 77% of PVG. At this point, I'm going to turn the conversation over to Frank Pici who is our CFO, to talk about our capital position derivatives and talk about our guidance, if you would.

Okay. Thanks, Jim. Good afternoon, everyone. What I'll do is focus my comments on the PVA side. Our press release speaks both to PVA and to PVR but I think if you go back to the conference call we had a couple hours ago on PVR you can get the gist of our comments there with respect to the hedging environment and the capital resources of that entity.

So that said, looking first at hedging and once again on the Penn Virginia Corp. side of the house, you can see that on a consolidated basis we had a large gain reported in the income statement and we sort of normalized that out when we look at adjusted net income but that said, I'd look at more at the cash impact of our hedging settlements during the quarter on our oil and gas price realizations and in the third quarter the payments we made to our counterparties effectively reduced our natural gas price realization by about $0.48 from a little over $10 to $9.66 and our oil realizations by about $7.50 a barrel which is from $117.50 down to about $110 a barrel so obviously still very strong price realizations.

Probably more importantly, looking forward on our oil and gas hedging positions, I think we mentioned in the press release that we've got a pretty solid hedging position in place for the fourth quarter, we're about 55% hedged. We've got a weighted average floor and ceiling of 850 by 1115 there. When you take that into 2009 we've hedged about 42 million cubic feet a day. That's more heavily weighted towards the first part of the year, the winter months in particular, and then in the spring and summer and the winter of '09, '010, those volumes drop off a bit. Point being, that those are very strong floor, ceiling prices, we, as usual have used primarily costless collars, those positions that are currently open as of early this week had an in the money value of about $36 million compared to the current strip that's out there for oil and gas prices. So it's a good underpinning for our capital program, both for the remainder of this year and for -- as we enter 2009.

With respect to our capital resources and debt position, I know that's a subject that's getting a lot more scrutiny these days with the sort of financial market meltdown we've had recently. On the Penn Virginia Corp. side of the house we ended the third quarter with about $300 million available on our revolving credit facility. What we would expect, given the guidance that's included in this press release and we'll go to briefly in a minute, based on our remaining spending for 2008, we would expect to exit 2008 with a revolver availability in the 230 million to $250 million range. So that gives use lot of dry powder going into 2009.

We have not yet announced anything formal regarding our 2009 capital expenditures plan. We are working on that now but in general terms I would say we expect to remain or to put forth a plan that will be much closer to internally generated cash flow than we've been in the last couple of years. Again, that will not put undue pressure on the credit facility and allow us to be sure we have a balance sheet that preserves capital. So we'll continue to do that. As I said, with respect to PVR, I would refer you back to the conference call we had on that a couple of hours ago. Again, on that -- in that credit facility we have some dry powder that we expect to be able to preserve as well.

Turning for just a second to guidance for this press release and for the rest of the year, just to make a couple of points and most of these things are explained by footnote in the press release. We have pulled on oil and gas production, we have pulled in the high end of the guidance down slightly from our previous guidance and that was also mentioned in the operations release, I believe we put out last week. And we've also adjusted somewhat the -- our capital expenditures guidance from the previous announcement to a range of -- on the oil and gas side of 590 million to $610 million for the full year. So again, a strong capital spending program for the fourth quarter but reduced slightly from what we had previously talked about. Other items on the guidance table remain pretty much similar to what we had on prior guidance so I won't go through those in detail.

I really can't add too much. I think between Baird and Frank you got a very good look at the details. I think what you heard is that the third quarter for Penn Virginia was a solid quarter, a very good quarter, really, in terms of the performance of our oil and gas company as well as PVR. It was a little bit of issue at PVR Midstream but again, that was Ike, it wasn't really an operating related issue.

As we sit here in the fourth quarter, I mean, we're all I guess in the same boat. The US and global economies have been rocked by tight credit and diminishing demand and falling commodity prices and if you can tell me what 2009 is going to do, you're a heck of a lot smarter than I am. What I can tell you, and Frank alluded to this, is we're going to be very cautious while we try to be as opportunistic as we can. We're not going to put ourselves in a position, if we can possibly help it, where we've got a financial gun to our head.

That said, you just heard Baird go through I thought in good detail what we're doing, in the lower Bossier and the Granite Wash, the Selma Chalk, the Pick 3, the Woodford shale, opportunities make themselves available on the Gulf Coast, we've got some interesting and maybe an overstating that, exciting things to do there and we also have some interest in the Marcellus Shale. So as the year unfolds and if access to the capital markets changes, that's fine. But as Frank just said going into the year, we're going to try to manage to stay very, very close to our cash flow. I know that many of you out there are trying to build your models and make your projections and you would love me to give you a bunch of numbers but I cannot do that. The budget for next year has not been approved. And it won't be approved until late in the first week or early in the second week of December. When it is, we'll put out guidance and we'll tell you as much as we can at that time. With that, operator, I would happily take questions.

Thank you. Ladies and gentlemen, we will now be conducting a question-and-answer session. (OPERATOR INSTRUCTIONS) Our first question is from Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Thanks, good afternoon. On the McKenzie well, I know you're not going to throw a rate at us at this point in time, but can you talk in terms of, drilling this well, how's it relative to say, like the original Fogle well and given what you know based on -- since it's been on and flowing from the frac fluid, how does it compare with the Fogle or is that not the right way to look at it?

Yes, I mean, that is sort of the right way to look at it. All three of these wells are sort of acting almost the same is how I feel right now. Maybe the Gibson, McKenzie, a tad less. But again, the Fogle well we opened it up and essentially got it down to line pressure within about a month and-a-half. Line pressure being about 600 times. In this case we're holding 2,000 to 3,000 pounds of back pressure intentionally and they appear to be cleaning up a lot better than what the Fogle well did. So for that reason, the way they're acting with the short production history as compared to what the Fogle well did, I think they're acting sort of the same. It's impossible to draw a curve on a well that some kind of forecasts on a well that's curtailed on a declining curve analysis. You just can't do it. It's got to be under a constant back pressure in order to accurately forecast. So constant back pressure in most cases is line pressure when it's all the way into the line. So at this time, we're pleased with how those two wells are acting.

Okay. And with the McKenzie, how long was -- when did that start cleaning up?

About two weeks.

And exactly how long does it take -- at what -- is it going to be another couple weeks until you have that thing flowing at a pretty nice rate or how long is that period between finish--?

Since we only got about 10% out of roughly 70,000 barrels of water we pumped away this is a lot of water we pumped away in these things.. Cleaning up at a 700 to 800-barrel of water a day rate, you can do the math. It takes some period of time. But as time goes on, and you get the bulk of the water out, north of 50%, you have a pretty good idea of what you have.

Okay. And I think you said, correct me if I'm wrong, that the Gibson doesn't seem to be -- you're not getting back much of the water from that and why would that be? Is it a pressure issue or is it maybe some faulting there or what would you attribute that to?

It was actually the Fogle well. The Gibson well is cleaning up just fine, just like the McKenzie. The Fogle well is where we had a hard time getting any appreciable water out of it in a short period of time. I don't know the answer to that question. Our thinking is, and this is very speculative of course, is because these pressures of these reservoirs is so high, when you pull on these wells hard to close your pressures, that being the pressure that packs your formation around the sand itself, it's so high that there could be some possible damage to that fracture. That's why people were using these high strength properties. Whether it's an embedment issue or some kind of deterioration of the frac itself or -- I don't know. But that's a possible answer.

Okay. And you did talk about looking at different ways in completing these wells and when you look at the -- what you did with the McKenzie and the Gibson, is that similar to how you did the Fogle? Would it be on sort of a go forward basis. Or was there something different in the way you completed the McKenzie well and being in the upper portion versus the lower portion.

Actually the McKenzie and the Gibson are both in the lower portion. We just started recently landing these things in the top. The reason being is we were seeing our better gas shales in the top as we drilled the curve through this stuff, number one. Number two is we're also seeing, based on production logs we ran at least on the Fogle well, we're actually seeing a larger part of our gas come from this upper part of the lower Bossier. So that's how we concluded that we probably need to keep the bulk of this ladder within another part of the lower Bossier.

Is that how other operators are doing it as well?

I don't know. Don't know the answer to that question.

Okay. I appreciate it. I'll let somebody else jump on.

Next question is from Joseph Allman with JPMorgan.

Hi, everybody.

Hi, Joe.

Hey, Baird, could you talk about the prospectivity of the Haynesville lime on your acreage?

At this time, Joe, it's really early. We completed -- if you remember some of the 17 vertical wells we talked about that we completed over the last couple of years it got us into this overall Bossier play. Three out of those 17 wells we did complete in this Haynesville line. And we had some -- I don't want to say large flow rates because they were not large. They were anywhere from 200 to 300 Mcf a day. Sort of like what we had in the lower Bossier. So does it have some possibilities? Yes, it does. It has porosity associated with it at least based on what the open hole logs tell us. We fraced it. It probably is suitable for horizontal drilling. So it's -- that's what's so interesting about this whole East Texas area. We continue to find new things to do. All the way from the shallower stuff down to the deeper stuff and maybe there's some deeper ideas yet underneath the salt in this area. So it's a very, very intriguing geological area, I can tell you that. And the more we learn, the more excited we get, just based on what we have seen and things to do going forward.

And then given some results that we've heard recently from other operators in the Haynesville line, are you thinking about testing the well there?

Yes, I can't tell you when we're going to do it. First on the drawing board is to get something done in the upper Bossier. The most important thing we're doing is trying to get our lower Bossier tested across our acreage. But it will definitely be something we try at some point in time. I just don't know when, Joe.

Separate issue, are you seeing any abnormally wide differentials or very low wallet prices in any of your plays?

The only area we've seen some basis that has gone -- that's created is up in the Arkoma specifically. We've seen some bases that has -- has been 300, 350, something like that. That's been the only area we've seen some bad things on the basis. Okay. And then lastly, maybe this is -- if we can get Frank involved here too. But when you're looking at getting your -- lowering your CapEx so it's within cash flow, is that purely just a cash issue or -- I mean, given the kind of strip pricing that we're looking at right now, are there some plays where just the economics are pretty marginal and it's not worth drilling at this point?

Yes, Joe, it's Frank. I wouldn't say it that way. I think it's more of a case of just preserving our liquidity at this point. I think that's the main reason we would want to spend closer to within cash flow.

Yes, I think, Joe, it's a fair thing to say that we -- to a degree, we'll high grade the portfolio. We'll go after the things that seem to have the best return because we want to spend less money but we want to grow our production and our reserves so we'll try to design a program that achieves both of those ends.

Okay. Very helpful. Thank you.

Next question is from Sven Del Pozzo with CK Cooper. Please state your question.

Hi, good afternoon. Yes, you mentioned -- I was interested in the array of the Haynesville wells. I don't know if you've got a more recent map that would allow me to place the newer wells versus the original discovery well. I know you mentioned it just in words. Maybe Baird you could help me to have a picture of where the well placements are. You said McKenzie was 20 miles north of Fogle and the Brown well two miles from Fogle. I'm not sure two miles in what direction and -- could you help me out there?

Yes, the Fogle Gibson Brown, Fogle development area is sort of down in the Southwest of our acreage. I don't have a map here in front of me. We made a couple small acquisitions last year that that's where these wells are, to the Southwest. The McKenzie is all the way up to the north of our acreage. If you have an acreage map, sort of in the tippy top of Harrison County.

Okay.

And the Gail Fur which is the other reference point, it's on the Eastern part of our acreage. It would be from the Fogle area, it's probably 10 miles.

Okay.

Sven, I know I shouldn't make light of these things, but tippy top is a very highly technical term.

I got the picture. We'll hear kitty corner next. You also mentioned [Steeg] 1H and Fogle 7H.

Fogle is down in the Fogle area, here the Brown and the Gibson. The Penny Jones is south of the McKenzie.

Okay.

Mileage wise, I don't know exactly. But if you know how our Phase I acreage is with GMX in the northern part of our 100% acreage, it would be like the McKenzie well would be in the northern part of our acreage. The Penny Jones would be about a third down, within that 100% acreage and the Steeg would be yet another third of the way down within 100% acreage and not too far away from the Phase I AMI area.

Okay. Thanks.

Got you totally confused.

Do you think the Mid-Con basis blowout, what might narrow that differential? Is there anything in the foreseeable future that might help lift realizations there?

Probably a good wintertime, number one. Number two would be the continuation in the activation of Rex East over to the East should help the problem in the longer term. More so in the shorter term, where we just have some cold weather.

Okay. And have liquids processing at Mount Bellevue, is that taken care of now?

Well, not completely. As far as I know, and I'm not the expert, and unfortunately Ron Paige is unavailable here, but the One Oak train as far as I know is still down and will be down for -- I think they went down for 30 days. I'm not entirely sure when they started down but it was within the last week or so as far as I know. No, Mount Bellevue to my knowledge, Sven is not completely up.

Okay. Thanks very much.

Next question is from Irene Haas with Canaccord Adams. Please state your question.

Hi. Just have a follow-up on your Midstream margin, understand that there is some unplanned event in the third quarter. Would fourth quarter margin be more like third quarter or slightly better?

Well, that's a tough one. If you'll tell me the prices, I'll give you the answer. We simply -- Frank, I'm kind of not putting you on the spot here. I don't think we know, Irene, what our margins per se are going to be. Frac spreads have certainly tightened an we have an array of ways of generating income in Midstream. One is fee based and that's about a third of our volume, 30% or so of our volume and that obviously is not necessarily dependent on prices unless people stop drilling. The POP stuff as gas or oil prices go down you get damage there a little bit and we've done some hedging and we can get into that if you'd like. Then on the keep-whole stuff where the frac spread really matters, it's -- obviously it's a matter of the ratio or the relationship between those oil and gas prices and I really can't predict them. It's so volatile. Steve Hartman is here, talk a little bit about hedging.

Well, Jim, sorry, Irene, this is Frank Pici. One thing with respect to the processing margins, up in the Panhandle of Texas what we've seen is there's been enough of a basis differential there that that's actually helped us on the frac spreads that we realized on our -- up in that complex. So that's helped some and as Jim mentioned the other thing that's becoming more and more important to the Midstream in particular is the fee based revenue. For example, we bought a system up in the Fort Worth basin this year that is ramping up, increasing volumes and having more wells connected to it as we speak. That is a fee based revenue stream and that stream will increase and we expect it to increase in the fourth quarter. So those things all help to offset any weakness in frac spreads or keep-whole processing margins that we make. The other thing on the hedging side, we are pretty heavily hedged for the fourth quarter, I think it's around 75% or so of our Midstream production. That should mitigate some downward risk and downside risk on our processing margins as well.

Irene, I hope that's at least a partial answer.

Yes, thanks.

Next question is from Richard Tullis with Capital One. Please state your question.

Good afternoon.

Hi, Richard.

Hey, Richard.

Looking at the Cotton Valley vertical wells, what do you expect your base production -- excuse me, your base production decline will be there next year, given that you don't plan to be running any rigs, drilling verticals?

That's also a play type where we see some fairly high N factors like I was talking about with the lower Bossier. It's probably in the range -- this is going to be an educated guess, by the way, because I don't have something here in front of me, but it's probably in the range of about 20, 25%.

Okay.

Is an aggregate.

Okay. What's your cost estimate on the Gibson well?

It's going to be around $7 million.

7 million?

Yes.

Has your thinking on the economics or what you're looking for in the Haynesville wells changed any recently or what sort of cost estimates and EURs are you still kind of building into your models?

Well, we're still using about 6Bs and about $7.5 million but I think in time we should be able to get our cost down, not only because we're getting better at it, number one. Number two, the cost side of the business is coming down, probably in the 6.5 million to $7 million range.

Okay. When do you think you'll update the next round of Haynesville wells? Are you going to wait until 4Q results? Or do you think you'll put something out interim?

I think, Richard, our MO has been to wait until the end of a quarter and unless we find something dramatic, we try to avoid putting out sort of an a well by well basis because I don't know if that's actually all that helpful. So we -- probably be the end of the fourth quarter. If something dramatic good or bad happens, we'll tell you, just as we did with that first Fogle well.

Sure. The only reason I bring it up is I know we had the first well result back in May and I guess since then we've just had the early results on the second well and it might be helpful since you have a good bit of drilling going on to get, maybe an update on several wells at one time on an interim basis just to help us size up what's going on, particularly since you guys are kind of early movers on the Texas side of the play.

I think that's not a terrible suggestion at all and we'll certainly take that under consideration. I think particularly -- I mean, we all understand what's going on here. If that McKenzie well and it's only one well, but if that McKenzie well has a very positive result, you can make some inferences from that. They are nothing more than inferences. If it does we surely would want to let you know that. Likewise, if it doesn't work, I think if we're going to announce good news, we announce bad news, we would tell you that as well. So maybe if we've collected a few of these, that's a good idea and if there's some interim operational report we could put out. I'm looking around the table and everybody here is nodding yes. So that's a good idea, Richard.

Thank you. We would appreciate it. And what about your access to profits in the Haynesville Bossier, does it look like that's going to be okay for you?

Profits? Yes, it is. We've had to open our self up to more than one supplier, pumping supplier. We typically utilize one company and we've had to use two or three companies now to make sure we don't have a problem. But that's not been a problem here recently. It is a problem some places. We've had to wait for propping up in the Mid-Con in one of our Granite Wash wells so it is a problem in the industry but we're such a good customer in East Texas that people will try to take care of us.

Okay and finally, do you plan to do any JV wells with GMX in the Haynesville Bossier?

That's part of the budget process. I would assume yes but at this point, their budget and our budgets aren't finalized. But I would assume yes.

Okay. All right. Gentlemen, thanks so much, appreciate it.

Thank you.

You're welcome.

Next question is from Biju Perincheril with Jefferies. Please go ahead with your question.

Hi. The next year's program, the roughly $400 million that you sort of indicated, does that envision keeping these five rigs active in Haynesville all of next year or is there a ramp-up in rig count?

I think where we stand today is we're expecting to run five, unless the situation changes for the better or the worse over the course of the year.

Okay. And then I know that 400 is just a preliminary indication, it's not a final number.

That's correct.

But what sort of -- how much of that is for -- would be for facilities and acreage acquisition versus drilling?

It would be small, Biju. Probably -- if I had to guess, it would be strictly a guess, I would say probably, 5, 6, 7% would be facilities and lease ag.

Got it. And then in areas that you won't cut back versus this year, can you quickly run through what are some of your top areas that activities are going to be curtailed next year?

Well, we're going to curtail the Davonia shale for the time being. We're going to curtail the Hartshorne CBM program. Those would be -- and the Cotton Valley. At this point in time, with that -- assuming it's a $400 million high grading your opportunities, the Cotton Valley doesn't cut the muster. At least for the time being, we would put that on the back burner. But we've got most of our leases held by production in East Texas. So that issue is almost behind us.

Okay. And then will you be still continuing with some testing up in the Bakken or is that?

Yes. We'll try to get a well drilled there between now and the end of the year and we have a new build that's supposed to show up mid-year next year. But our intent to be to go ahead and start drilling Bakken development wells up there.

Okay. Thanks.

Thank you.

(OPERATOR INSTRUCTIONS) The next question is from David Snow with Energy Equities. Please state your question.

Yes, hi. What's the acreage now in the Haynesville?

62,000 net acres.

Okay. You spent $70 million in the third quarter on principally Haynesville, is that where you--?

It was about $50 million in Haynesville, almost $50 million in Haynesville. There was I think roughly $10 million in the Marcellus.

Did you have to pay -- how much an acre have you been having to look at down in the Haynesville?

The max we paid, it was only for a very, very important acreage in our mind, it would be -- it was about $25,000 an acre. I think in total, for the acreage we picked up from the time that we made the announcement of the Fogle 5 well, I think our average cost was about $800 an acre.

Okay. All right. Thank you very much.

Thank you.

There are no further questions in queue. I would like to turn the call back over to management for closing remarks.

Well, thank you. I see a board here that says there were over 65 of you on the call and I'm sure many more on the Internet so we appreciate the interest. I congratulate Baird and Frank for doing a great job I thought of explaining some complex issues and we'll look forward to talking to you next quarter.

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