Ranger Oil Corp (ROCC) 2008 Q2 法說會逐字稿

Welcome to the Penn Virginia second quarter 2008 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) It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer. Thank you. Mr. Dearlove, you may begin.

Thank you, and good afternoon. Before I get started, I'll tell you that I'm joined here in Radner. I'll just talk about people I expect might speak, Frank Pici, who is our CFO; Baird Whitehead, who runs our oil and gas company; in Kingsport, Tennessee, we have Keith Horton, who runs the coal segment of PVR; and in Houston, we have Ron Page, who runs the Midstream Natural Gas segment of PVR. I may not call on them to speak, but if we get questions that pertain to their areas, we'll certainly have them available to talk to you.

I'm not going to read the release, but I am going to sort of follow it along and if you -- if I miss something, one of these guys can fill in or you can ask me some questions or any of us some questions. From an operational perspective, PVA I think enjoyed a very good second quarter of 2008, with record results from our oil and gas segment as well as both segments of PVR, the coal natural resource and Midstream natural gas segments. Again, not to read it all to you, but to try to hit the highlights that were on the first page of the release, oil and gas production was a quarterly record at 11.4 billion cubic feet equivalent or 125 million , almost 126 million a day. That's about 14% higher than it was a year ago and 9% above the first quarter.

Quarterly operating income was $106 million, which is well above what it was in the second quarter of 2007 and was a record quarterly operating cash flow in non-GAAP measure was also a record and again, almost double what it was a year ago. We try to point you to quarterly adjusted net income, which is another non-GAAP measure, but what we do is we exclude the effects of the noncash change in derivatives fair value because we mark those derivatives to market, they are pretty volatile and really what they say on any given day is information I suppose, but I don't know that it's terribly useful, so we try to talk about adjusted net income and that was up, again, almost double from what it was a year ago. And in all candor, we also give you the net income line, which actually was a loss of $3.8 million. Virtually all of that due to this noncash expense associated with the valuation of derivatives. When Frank Pici gets into some discussion of derivatives or if there's any questions, we are obviously very willing and happy to talk about that.

There was a slight increase in our production guidance for the year, the midpoint now at 50.7, or about 136 million, or 138 a day, million a day. We've reaffirmed our guidance with regards to cash operating expenses and you may have noticed our LOE costs were down from the first quarter given the rise in expenses or costs of doing business, we're reasonably pleased with that. With regards to CapEx, we're now suggesting and the Board approved last week a 22% -- I'm just comparing midpoint increase to about $637 million, up from about $500 million. A lot of that has to do with lease acquisition, particularly in the Haynesville, but it also has a lot to do with increased drilling and when Frank walks you through the guidance, I think he'll have something to say about that. Finally, because I did mention we have some non-GAAP measures in what we present to you, I would remind you that these measures are reconciled and put on a GAAP sort of basis on the release.

To be a little more specific about our results, the operating income from our oil and gas segment was about 95% higher than it was in the second quarter of 2007. Likewise, our Midstream natural gas operating income was up 107% to $20 million. Coal's operating income, again, comparing to the second quarter of 2007 was up 37% to $24 million and all of these numbers were higher than in the first quarter of '08 as well. Various expenses, G&A, operating expense, exploration, DD&A, were higher than they were -- a little bit higher than they were in some cases in '07 and again, the press release attempts to delineate that for you pretty carefully. A lot of that driven by higher production and increased staffing, but as I said, LOE costs were actually down a little bit.

As you, I hope know and had a chance to read, PVA issued an operations release for PVOG on the 31st of this month -- excuse me, 31st of July, so about a week ago and I won't, again, read it to you. I am going to try to summarize it and then Baird can fill in the things that I miss. As I said a minute ago, oil and gas production for the second quarter of '08 was a new record at about 11.4 Bcfe or $125.7 million a day. Year-over-year production growth, therefore, was, again up 14% over a year ago quarter and 9% over the first quarter.

On a CapEx front, we spent $126 million, 102 of that drilling wells. Clearly to get up to that 635 number, we're going to spend a little bit more in the second half and, again, we can speak to that in the question or guidance part of this call. We drilled 49 gross and 32 net wells in the second quarter, 48 gross and 31 net were successful and one, which is a Marcellus test in West Virginia, not Pennsylvania is still waiting completion and under evaluation. We were fairly pleased with our horizontal drilling in the various shales. In the lower Bossier, or Haynesville, you can call it what you like, we announced a success in May, we're about to finish up on what we call brown number 8H, which is a couple miles from the well we drilled and announced and we're drilling -- we have spud what we call the McKenzie well, which is about 25 miles north of these other two, and will really help to delineate what our properties might contain.

Looking at some of the regional highlights, in East Texas, production was up considerably 112% over what it was a year ago and 26% over the first quarter. That's driven mostly by Cotton Valley development. As you may recall, we're drilling now mostly on 20-acre spacings. It's also been helped by the fact that PVR's Cross roads plant has just recently come online and we're now getting credit for the NGL volumes. That will become more apparent in the third and fourth quarter. The first of those lower Bossier or Haynesville wells, the Fogle number 5, as I said, we announced that well. It continues to produce pretty much as we would have expected and it's produced in its first 50 days of life approximately 250 million cubic feet equivalent. We have built and placed in service a 10-inch pipeline to serve this well and subsequent wells in the area. It's to be determined whether that gas needs to be processed. If it does, it will go through the PVR plant. If it doesn't, we'll make some other arrangement to get it down to Perryville. But as -- I think the important thing is we said we were going to build that pipeline and it has now been complete.

We frankly, think it's premature to predict ultimate reserves in this Fogle well, but we're certainly very encouraged by what we've seen so far. The Brown number 8, as I said, is about 2 miles away, which should be finished up by the end of August. Baird can obviously put some color around this, but I think what he'll say is it appears to be performing like the Fogle 5 but we don't know and we won't know until we've completed it. And certainly the McKenzie, while we're all waiting eagerly to see what it's going to say, we don't know and obviously while it's an important data point, it's only one data point. And regardless of the outcome of that well, we would expect to drill some more in that area. In fact quite a few more wells. We're intending to drill 13 lower Bossier wells this year. We'll have seven rigs running in East Texas and either three or four of them committed to the Bossier.

In the Mid-Continent, in the second quarter, we ramped up our activity, as we said we would. We drilled 12 gross and 5 net wells, including a couple wells in the horizontal Granite Wash, which been very prolific, some Hartshorn horizontal CBM wells, and of interest to us is we've drilled or participated in three horizontal Bakken wells in Dunn County in North Carolina. Those wells have two of the three have performed very well, the first one is only making about 50 barrels a day of oil. That really is not commercial, but it's a data point. More importantly, the second operated well is making about, a little over 650 barrels a day, which is very good well and we've got another one, in which we have very small working interest, but again, data that's making 545 barrels a day. And depending on the availability of rigs, we're encouraged enough by what we've seen that we would intend to drill at least four more of those wells this year.

We've got about 57,000 acres in the Bakken, just to put it in perspective, and I'm going to say that 60% of that is -- we would consider to be prospective. The other is to be determined, but we're not, we're not holding out a hell of a lot of hope for it.

The horizontal Granite Wash wells were, as I said, very pleasing to us, having IP rates of 12 million a day on one, 4 on the other. We now anticipating on a net basis drilling between 9 and 10 of those wells this year. Likewise, we'll ramp up our Hartshorn coal activity this quarter and bring on a third rig sometime in August and lastly in the Mid-Continent, when it comes to the Woodford, although we have a fairly small working interest in these three wells that are in the Arkoma, the IP rates listed in the release of 1.6 million, 4 million and 3.3 million a day equivalent encourage us and we'll see more activity there in the rest of this year and certainly going into 2009.

Very briefly in Mississippi, as you know or you may recall, we're switching over to a horizontal program there. Those wells have been quite prolific, but as a result of switching over, needing to upgrade the rigs, we slowed down production there, so it's fairly flat compared to a year ago or even the first quarter of this year, but by the end of this quarter, the third quarter of 2008, we would expect to have two rigs dedicated to the horizontal drilling there and a third one coming online hopefully in the second quarter of 2009. This is, this is an important play to us. Not a lot of sex appeal, but a very predictable and prolific play. In Appalachia, during the second quarter, we drilled some more of these horizontal CBM wells, to be specific, 3.3 net. All of those were successful. We drilled that Marcellus shale exploratory well and that's in West Virginia, not in Pennsylvania or New York, we don't know yet what it's going to tell us. We're testing it as we speak.

Appalachia production was actually down compared to a year ago quarter and up a little bit over the first quarter this year. We had some permitting issues that slowed down the drilling activity in the fourth quarter of 2007 and earlier this year. We think a lot of that's behind us now. We've got an inventory of permits that should allow us to go forward, running three rigs and maybe four there to be determined.

The horizontal development program in the lower Huron shale is going along quite well in Mason county. We've got three wells drilled, with two additional wells expected later this year. We put in place the right of way for a 10-mile pipeline, which we expect to construct and build later on this year. We're testing some ideas we have in Boone County, West Virginia. That will be done also in the second half of this year, and finally, in the East -- in the Marcellus in Pennsylvania and New York, we're to run 21,000 acres, which doesn't make us a real big player there. We got into the play, though, fairly early. Our average cost is only about $400 an acre. It's something we're very interested in. We're a little cautious about the infrastructure and political problems that I think operators are going to encounter there and so we're trying to pick our spots where we think they -- the sweet spots of the Marcellus may be and we probably won't test any of that, this year it will be early 2009 before we get going there. We got plenty to do in those other places I just mentioned.

In the Gulf Coast, we did not drill any wells in the second quarter and consequently thinking of the decline curve one has in South Louisiana, production was down relative to the second quarter of 2007 and a little bit lower than the first quarter of this year. However, that's still an important area to us. We intend to drill several wells this year in South Louisiana and South Texas and in fact are commencing a development program in what we call (inaudible) sometime here in the very near future.

Switching over for a minute to PVG and PVR, as you may know, PVA -- I hope you know, owns 77% of PVG. PVG is Penn Virginia GP Holdings, L.L.C., the general partner of PVR, PVR being Penn Virginia Resource Partners and the natural gas Midstream and coal natural resource MLP. Both segments, as I said earlier, that underlying MLP had terrific quarters. PVR establishing quarterly records for distributable cash flow as a whole, as well as operating income and adjusted net income, as was the case with PVA. Net income was somewhat negatively effected by noncash hedging expense. PVR Midstream had throughput volumes that were a record of over 260 million a day, up considerably from the second quarter of last year and the first quarter of this year when they were averaging about 190 million a day. Gross margins at $1.34 are very strong, well above last year, but a little bit below frankly, the first quarter and that's all about the volatility, obviously as we're all aware of oil and gas prices. Coal production was up 10% over what it was a year ago and more than that over the first quarter of this year to 8.8 million tons. Coal royalties at $3.58 or $3.20, if you subtract out operating expense. We're well above the $2.98 we got last year and the $3.14 we got in the first quarter. That's a reflection of some more additional met coal coming off of our properties, as well as coal prices going up sort of across the board.

Looking ahead, we would expect PVR, because of -- particularly because of the acquisitions we made in the first half of this year to have a pretty strong second half and be very well positioned for 2009 and beyond with a lot of organic growth opportunities on both sides of the equation. Maybe of more relevance to the folks on this call is PVA's -- is PVG's, excuse me, announcement that as of the 20th of August this year, it will pay a quarterly cash distribution of $0.36 a unit or $1.44 annualized. This is 6% roughly higher than it was last quarter and 28.5% higher than it was a year ago. This quarter, the cash to PVA would be just under $11 million. I think what I'll do right now is -- Baird, unless you want to add something, I'll have Frank--?

That's fine.

Okay, then. Frank, if you would take us through capital resources, derivatives and guidance.

Sure, Jim. Good afternoon, everyone. I'll do it a little different order than the way it's in the press release. I guess I'll start off with the derivative section and then speak to guidance and capital resources. On the derivative side, you saw on the income statement that we had a large mark-to-market expense for hedging in the quarter, 100 million , almost $104 million. About $74 million of that was from the oil and gas business, another $30 from the Midstream business and PVR and of course we give you some adjusted net income numbers as well to adjust out the non --- the unrealized noncash part of that and just give you the cash portion on unsettled hedges.

If you look at that number, of course with our mark-to-market accounting, it's a very volatile number and if you look at the end of June, we had a -- on the oil and gas side, for example, the oil and gas derivatives had a fair market value of about $86 million liability, as of August 5, that was down to almost zero, it was less than $1 million, so that just illustrates the volatility based on the strip and how that strip changes. So, of course, that's one reason that we believe that this adjusted net income calculation is relevant in that it gives you really the cash impact of the hedging program. Similarly on the Midstream side, those positions changed as well, not quite as significantly. I think they went from mid 30 million to I think they were about 38 million at the end of June to about 27 million in the beginning of August, so again, a lot of volatility.

When you look at the impact of our hedging program on our price realizations, in the second quarter, we had obviously very record -- near or at record, I think they were record prices for natural gas physical sales. I think we realized prehedging prices of about 11.24 an Mcf on the -- when we take and factor in the settlements on the hedging side we give about $0.80 of that back, so post hedging realized about $10.44 an Mcf, still very high. And of course the fact that we had those high prices and this high hedging settlements are just reflective of the physical markets we had for the second quarter. Similar to that and of course the revenue's not quite as high of a contribution is natural gas. But on the oil side, we gave it back about $2.63 a barrel off of $121.54 physical sale price on the oil side as well, but, again, very high realizations.

Looking forward, our -- based on current production levels for the rest of 2008, the second half of 2008, we're about 53% hedged. We've got across all of our areas natural gas hedging positions and by the way, most of what we have hedged, if not all, is natural gas now. The average floor price is $8.34. The ceiling is $10.06. Going into 2009, we currently have about 30% at current production hedged at about an $8.75 by $11 collar, and we have some positions into the first quarter of '09. That's about 20% of our current production for the first quarter of '09 hedged at $9.30 by $13.45 so I think they're very healthy positions going forward and those will support our cash flow needs for our capital spending program.

Switching over to guidance for a minute and then I'll get into, get into our capital resources, if you look at the guidance table back on page 13 of the release, just to highlight a few things, as we have said in both the operations release and the earnings release, we did narrow the guidance on our production, narrowed the lower end of our gas production guidance, natural gas and oil production guidance slightly. We did show an expected improvement will continue in our operating expense category under oil and gas. We tweaked our DD&A, or depreciation, depletion, amortization calculation, upward a bit to indicate both increased costs and a different production mix as we go through the year and know more about that.

Most significant change in oil and gas was in our capital expenditures program. We've increased that by 135 million to $140 million over our previous guidance. The three main components of that were our drilling program and our development and exploratory drilling, we've got, as Jim mentioned a minute ago, more wells. We've got 15 to 20 more net wells planned than we had in our previous guidance. The biggest components of them are in the lower Bossier, Haynesville play and in the Granite Wash and Bakken plays in the Mid-Continent. We've also got some additional drilling in the Marcellus Chalk program, a little bit of Appalachia horizontal drilling and there's also some inflation built in there for drilling costs. So those are the main drivers for that increase in guidance on the drilling side.

As Jim mentioned also, we've increased our guidance for leasehold acquisition spending. That, again, is primarily in our -- in the Haynesville, lower Bossier area and to a much lesser degree in Marcellus and Appalachia. We've got some additional facilities costs as well, it's primarily some pipeline-related installation costs in East Texas. So those are the main drivers on the PVA side. I won't go into as much detail on the coal and natural resource segment and Midstream segment both of which are in PVR. We had gone through those in the earlier call just to say that we refined our ranges a bit on the coal side and the Midstream side. We've increased our coal realizations as a function of the higher price realizations that PVR's lessees are seeing in their coal sales and otherwise, upgrade -- updated the guidance for capital spending for known acquisitions that we've made, some organic spending in both of those segments. So with that said, that's pretty much all the guidance.

Just a comment on PVA's capital resources, we ended the second quarter with $205 million drawn on our revolving credit facility. That's a $479 million available facility. As we walk from the end of June to early August, that number's gone from 205 million down a bit to about $175 million. That leaves us with about $300 million available on that $479 million facility, which we think is fully adequate to fund our capital program through the rest of the year into '09. The reason it went down between June and early August was the -- we had sold some PVG units. We sold a couple of million units out of the position we had there, took our ownership in PVG down from about 82 to 77%, but obviously still a very significant ownership position. We also sold some non-core lease hold positions we had up in North Louisiana. So like I said, plenty of capacity going forward from a capital perspective. Now, Jim, I'll hand it back to you.

Okay. Well, thanks, Frank. Let me just sum it up and then we'll take whatever questions you might want to ask. As we said in the release, and maybe you got from the tone that both Frank and I employ that PVA had a, we think a very good quarter, again, particularly from an operational and a cash generation perspective, and we believe that our ongoing success in the Cotton Valley and Mississippi and Appalachia and Mid-Continent which kind of gets lost sometimes in all of this shale hype -- it's not hype but it's excitement, let me call it, it's just very solid and we would expect that the shales that we're involved in, the Haynesville, the Bakken, the Woodford, the lower Huron, ultimately the Marcellus will only add to that.

So we're quite encouraged by the way the Company is positioned and as Frank tried to just tell you, I think on a capital front, we don't have a gun to our head. We can easily afford the kinds of things we're planning to do. PVG Group, PVR is very well positioned and I kind of gave them short shrift here today, but I would remind you that if you go to PV resource.com, which you can link to from our PVA website or go direct, you can see their press release if you haven't seen it and I'm not sure when it will be posted, but we had a 45-minute call here earlier today with some very good questions on it and Ron and Keith both gave a chance to give their views on their respective operations and so I would encourage you, if you're interested, to go and listen to that. So in short, regardless of the extreme and to me often indecipherable volatility in the equity markets, PVA, PVG and PVR, in my opinion at least are very well positioned for future growth and profitability and so with that, operator, we'll take some questions.

Thank you. (OPERATOR INSTRUCTIONS) Our first question is from Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Good afternoon.

Hi, Scott.

Baird, on the Fogle well, what can you tell us about that well right now? Can you say what the current flow rate is and whether it's restricted or not or do you have it open flowing? What have you learned from drilling and completing that well and have you applied anything differently to the -- I guess your subsequent well that you're drilling right now?

Scott, that well's making right now, and it's essentially floating on a line of pressure, about 500 (inaudible) it's making about 3 million a day, but I don't want to call it strange. What's ironic is that well is essentially stabilized at that rate. I'm not going to say that it's not still on somewhat of a decline, but it's a very, very low decline rate. Some of the numbers that are out there as far as 5 Bcf, 6.5 Bcf, 7 Bcf, with that kind of rate at the end of almost 2 months now, it's very easily, very easy to extrapolate to these kind of reserve numbers that you have seen. We're not ready, as Jim said earlier, to say what our average reserves are going to be in this play, but we still are very encouraged as far as what we have seen and remain so based on some of the drilling indicators that we've seen on the Brine well and even recently on the McKinsey well.

As far as what we have learned or what we may do differently, we're going to try to get additional frac stages away on this Brine well, we of course, not only because of additional frac stages, but because of each individual frac stage, we will put more sand away per stage. One thing we've also learned that -- and we think to some extent it may have had a negative extent on the Fogle is we shut that thing in for about 2 weeks after it had been online for two to three weeks to drill out those packer sleeves and those inflatable packer systems that we utilized to do the stage jobs, the frac stage jobs. Probably on the Brine going forward, we're going to go ahead and get those packer sleeves drilled out immediately to keep that thing flowing after the fact, because, you pump a lot of water away in these things. We think once you get these things flowing back, you need to keep it flowing back and not have to shut them in for any period of time to do anything. So that's the plan going forward. I think that's, I think that's about it.

Yes, no, that's very good. Thanks. And so basically just to drive into it a little bit, you kind of indicated that the range of wells that are being put out there right now are reasonable and if you look at sort of the Fogle and understanding this has obviously had been shut in for a period of time, which could have impacted the rate, but based on what it's doing right now, is it meeting or exceeding your sort of internal models?

I could tell you, it's exceeding what we internally modeled this thing going into it, yes.

Okay, thank you. And Frank, on the balance sheet, looks like you guys are pretty well set up to take on the extra spend you have this year. What are the thoughts in 2009 and I guess for Jim and Frank as far as how active you get and are there any areas that you would think about divesting in order to really accelerate in others?

Let me answer that, we have -- as is clear, quite an extensive portfolio of assets and as time goes on, I think a prudent manager looks at that portfolio and decides what's the best use of capital in the short-term and what's important to be sustainable in the long-term, and we will -- we sold, as Frank said, we sold a little bit of PVG, although not to call it non-core. That was to help augment an acquisition frankly that PVR made, so maybe very clear about that, but we were willing to do that. We sold some what we thought was non-core leasehold in Northern Louisiana. We have other areas that are probably less core than, say, the Haynesville is. And we will look at them. Our goal, I suppose, is not to go around divesting things, but to be prudent managers. And so we were not going to let our balance sheet get out of whack. If we have to sell something because we're getting a better return and let's say the McKenzie takes off, we'll do what we have to do.

Okay. So would the preference be to look at paring down the asset base versus say, look at the capital market just sort of in mid '09 you really felt the need to accelerate?

I notice that you had a price on us of $100. Maybe we ought to get out right now, I don't know, but we're not anticipating doing that and I would think we don't feel any gun to our head, Scott, to reaccess the capital markets.

Hey, Scott, again, just to reiterate what Jim said, this is Frank, I think between the combination of things between -- we'll see what equity markets look like next year and what opportunities we have in front ourselves, but we certainly have some non-core assets we could divest as well and the other thing to keep in mind, is that with a growing reserve base, our -- unless there's -- unless there's some short of a meltdown in the banking markets overall, with the secured borrowing base, I would think we could continue to increase that as well, so we've got several ways to continue funding growth here.

All right. Appreciate it.

Thank you.

The next question is from Steve Berman with Pritchard Capital Markets. Please go ahead with your question.

Hello, guys. Baird, maybe it's premature to ask this but in the Williston Basin there's a lot of excitement over the Sanish and Three Forks and I was just wondering what you think of the prospectivity in your acreage for those formations.

Steve, we really don't have any data as far as the Sanish Three Forks interval. The plan is once we get a rig lined up to initiate a development program, we will go ahead and drill a couple of these things via pilot hole, down through that interval and see what we have. But we have no information whatsoever on our lease hold as far as what potential that has on that hold.

And I'm sorry, what did you say your acreage was up there now, your total acreage?

Well, if you talk about in total, you talk about in total, we've got over 60,000 net acres, but it's probably 15,000 acres of that that we think has little potential. In the area that we drilled these three wells recently, we've got between Dunn County and McKenzie County about 29,000 net acres.

Okay. Moving to the Haynesville Bossier, your joint venture partner in their release said that they expect PVOG to drill two gross and 0.8 net Haynesville Bossier horizontal wells in the joint venture acreage in the second half of 2008. Can I get your views on that statement?

Yes, I mean I -- to be honest with you, nothing's iron clad as far as what we're going to drill in the Haynesville this year, but I would say based on AFEs that we have sent to GMX, that's realistic. I would say most of our activity's going to be on 100% acreage.

All right, thank you.

You're welcome.

The next question is from Irene Haas with Canaccord Adams. Please go ahead with your question.

Yes, one more question on the Bakken. You said 29,000 net acres. That's the 60% that looks looks prospective, right?

Really, Irene, we think probably -- we have been very conservative as far as what we think we have there right now. We think that probably more than 60% is prospective. I can tell you that probably out of the 29,000 we have based on the one well we drilled that did not perform, there's probably only 4,000 or 5,000 net acres that we say probably has been condemned. So that leaves 24,000, 25,000 net acres that still could be perspective in the Bakken in that overall area, which is more than the 60%, of course, but we've got to get some more wells drilled and we just approach this conservatively at this point in time as far as offset locations we feel real strong about.

Okay. Well, you started the year, in the beginning of year going to drill two wells in the Williston Basin, obviously you upped your rig count. What could we look forward to next year and what are your major decision point are you going to go in and treat it like a development project? How does the Williston rank? What can you -- looks like really healthy portfolio? Is it like a number two or number three?

I would say it's really up there, I hate to rank something at this point in time because considering well prices it's right up there. Our plan going forward is to go ahead and kickoff a development program as in a lot of areas, we're having a hard time finding rigs at this time, we have already committed to a new build that would not arrive until the second quarter of next year, but our plan is to go ahead and initiate a development program with at least one rig as soon as we can.

Thank you.

The next question is from Bob McDorrman with Investment Counselors of Maryland, please go ahead with your question.

How are you, Bob?

Pretty good, thanks. You made a significant increase in your budget this year and would you have increased it as much if, if you had felt or the price of natural gas had already come down and let's say we were looking at an average price of $8 going forward instead of the 13 that we got to? At what point is the Haynesville maybe not quite as exciting in terms of--?

Well, Baird, what do you think on the Haynesville?

Well, since most of our acreage we have in East Texas is perspective on the Haynesville was acquired because we had Cotton Valley potential in our sights you look at it incrementally as far as Haynesville goes, the rates of returns on those wells are very, very high. So to answer your question, $8 at Haynesville based on how we have this thing modeled at this time still clearly flies with those kind of prices.

And, the first part of your question was what would you have upped this budget this much if gas prices were $8 and you were comfortable or your model said that's where they were going to stay, we would have upped it considerably because the Haynesville, when that lower Bossier well worked that opened up a whole new horizon because just to refresh your memory, we drilled, I believe the number is 15 vertical tests on our 50-odd-thousand acres, it's up to about 60,000 now. We've seen that lower and upper Bossier in most, if not all of those tests. And we've thought for more than two years that a horizontal lower Bossier well would work.

When it did, that opened up just a bunch of new opportunities and we would have certainly been aggressive leasers, I think if gas prices were $8, leases wouldn't be going for 30,000 an acre. Our average lease cost in all of that stuff is in the low thousands of dollars and when we leased it, we were leasing the Cotton Valley, not the Haynesville. So the numbers would have changed, but the -- I think the philosophy wouldn't. The fact the Haynesville worked, the fact the lower Huron is working, the fact we think we are learning a little something if maybe viscerally about the Marcellus, the fact that the Woodford is working, the fact that the Bakken worked, none of those things did we know when we drew our budget last fall. They are all working and so we've -- in some senses have an embarrassment of riches, but we surely would have taken advantage of them, no matter what the price of gas, unless it was $6 and we thought it was going to stay there forever, which we don't.

Okay thanks.

I hope I answered it.

Yes, thanks.

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

Hi, good afternoon. Baird, I think in the -- well, one of the frac stages was located in the upper Bossier section. Is that what you plan to do with the (inaudible) well, or is that going to be all in the lower Bossier?

Probably that last interval will also be in the upper Bossier, Biju, just because we pick up a tremendous amount of gas as we drew out from underneath the Cotton Valley and that upper Bossier, even though it's a different animal than the lower Bossier, it appears to be naturally fractured and has a lot of free gas in place and that's when you start increasing your mud waste in order to control that. But to answer your question, we will probably in all likelihood complete that upper Bossier in that last stage.

And then I think you had -- initially you were planning on putting one well entirely in the upper section. Is my understanding there correct? Is that still your plan?

That's correct. Whether we get that done this year or not has not yet been decided, but, yes, we will do that for sure.

Okay, and then in the Bakken, did I hear you right that the first well that was a geology problem, not a mechanical problem or?

No. We feel it's a geological issue. The Bakken works because it's a Dolomine, we do our first well, it appears that the majority of the hole in the ladder was not a Dolomine and in fact was actually a limestone, which impeded production because it's extremely tight. So, yes, to answer your question, it's a geological issue.

Okay. So does that condemn the acreage to the lesser of that well, or I guess that was on sort of the western edge of your acreage there, correct?

It's actually on the southern part of our acreage and we think that well has condemned the southeastern part of our overall acreage block.

Okay, and you said that's about, you said 5000 or 6000 acres.

It is about 4000 or 5000 net acres, yes.

Okay. Thanks. That's all I had.

You're welcome.

(OPERATOR INSTRUCTIONS) The next question is from David Snow with Energy Equities, Inc. Please go ahead with your question.

Yes, hi, I've been trying to ask if the convertible note, $125 million, has any limit on the amount of whatever it is, $230 million, if it has a maximum and number of shares it's convertible into?

It's about 3 million -- prices went to infinity, it would still be about 3 million new shares issued.

Oh, okay. And it sort of goes on a straight line from here to there?

It starts to level off when you get 30, $40 into the money.

Okay, all right. Great. And in the Bakken, can you give me an idea what, how many stages you've been fracing?

David, we -- the two wells -- the second well, because the first well's not a good data point because of the geological issue, but the second well, we did nine stages in.

And how long was that?

It's about -- it was about 9000 feet.

Okay, and you had a third well also. What was that, or you have small interest in the third well?

Yes, the third well, we had a small interest in, but it was also about 9000 feet.

What would be the same question for your Fogle well in the Haynesville?

It's about 4000 feet.

And how many stages?

Well, we'll plan on -- we did seven stages on the, on the ogle well. We plan on doing eight stages on the Brown well.

Okay. Thank you very much.

You're welcome.

Thank you.

The next question is from Richard Tullis with Capital One Southcoast, please go ahead with your question.

Hi, good afternoon. Great quarter. Going back to the Fogle well real quick, Baird, looking out over the first 12 months production, what's your expectation for this well? What do you think it will do?

I think it would be premature for me to answer that question, Richard. I -- before we start throwing numbers out there, we need to get some more production history under our belt. I would prefer to leave it at that at this point in time.

Sure, that's fair enough. What's your average royalty on your total Haynesville Bossier exposed acreage?

It's about 80%, a little north of 80% would be an accurate number. The new releases when we picked up here recently because of the Haynesville are a quarter and a lot of the earlier leases we had picked up with GMX -- or that's not even GMX, Cotton Valley and in mind we have anywhere from 80 to 85%, so I would say about 80%'s a good average.

Okay. On the Bakken wells, what are they producing now? I know you had the rate out there about a week ago, but what are they at right now, at least the two larger ones?

Well, the two larger ones, and I need to expand upon the good one that we drilled, we have yet to get in there and drill out the -- that's out of the thick but a few hundred barrels a day.

Okay, and last question, what's your current total production?

As we speak?

Yes, if you've got it.

135's about right.

Okay. That's all for me. Thanks so much. Appreciate it.

Thank you.

You're very welcome.

The next question is a follow-up from David Snow with Energy Equities. Please go ahead with your question.

Yes, wondered if you could give us gas -- per section estimate for your Haynesville, lower Bossier, whatever?

Well, for the lower Bossier by itself, we're using about 100 Bs in place per section and if you assume 20% of that is recovered that's 20 Bs per section take it across our lease hold, but we have at least probably 1.5 Ts of reserves, net reserves based on our acreage position. That would be on the lower side. And that does not include the upper Bossier by the way also.

How much would it add if you included the upper Bossier?

The upper Bossier, and I don't have the math here handy, but we feel it has about another 50 Bs in place, about another 10 Bs recoverable per section.

Are you the only one that's perforated in the upper Bossier, along with the lower Bossier?

I can't answer that question. I do not know.

I haven't heard of another one doing that. Sounds like you're out in front on that, doesn't it?

I think we've got probably a slight different geological issue between the North Louisiana activity and what we're seeing over our way.

You have separates our more on your side than on North Louisiana?

I'm just speculating at this time.

Yes. Okay. Thank you very much.

You're welcome.

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

Thank you, and thank you, those of you on the line. The queue says there's 60 some of you and I'm sure there's quite a few more on the Internet. So we appreciate the time and the interest and the questions and we look forward to talking to you at the end of the third quarter. Thank you very much.

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