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Penn Virginia Corporation (NYSE:PVA)

Q2 2008 Earnings Call Transcript

August 7, 2008 3:00 pm ET

Executives

Jim Dearlove – President and CEO

Frank Pici – CFO

Baird Whitehead – EVP

Analysts

Scott Hanold – RBC Capital Markets

Steve Berman – Pritchard Capital Markets

Irene Haas – Canaccord Adams

Bob McDorman – Investment Counselors of Maryland

Biju Perincheril – Jefferies

David Snow – Energy Equities Inc.

Richard Tullis – Capital One Southcoast

Operator

Greetings ladies and gentlemen and welcome to the Penn Virginia Corporation second 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 recorded. It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer. Thank you. Mr. Dearlove, you may begin.

Jim Dearlove

Thank you, Joe, and good afternoon. Before I get started, I'll just tell you that I'm joined here in Radnor – I'll just talk about the people that I expect might speak. Frank Pici, who's our CFO; Baird Whitehead, who runs our Oil & Gas company in Kingsport, Tennessee; we have Keith Horton who runs the Coal segment of PVR; and then in Houston, we have Ron Page, who runs the midstream natural gas segment of PVR. And 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 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 do try to hit the highlights, we're 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, a 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 we do is we exclude the effects of the noncash change in derivatives fair value because we mark those derivatives to market. They're 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 and/or if there is any questions, we obviously are very willing and happy to talk about that. There was a slight increase in our production guidance for the year, midpoint now at 50.7 or about 136 million or 138 million a day. We've reaffirmed our guidance with regards to cash operating expenses, and you may have noticed our LOE costs were down in the first quarter. Given the rise in expenses or cost 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 acquisitions, particularly in 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'd remind you that these measures are reconciled and put on a GAAP sort of basis in 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 new record at about 11.4 Bcfe or 125.7 million a day. Year-over-year production growth therefore again was up 14% over a year ago quarter and 9% over the first quarter.

On the CapEx front, we spent $126 million, $102 million 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 then 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 drills and 31 net were successful and one which is a Marcellus test in West Virginia, not Pennsylvania, is still awaiting 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've announced a success in May, we're about to finish up on what we call Ground Number 8H [ph] which is a couple of 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 I think 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 quarter, and 26% over the first quarter. That's driven mostly by Cotton Valley Development. As you may recall, we're drilling our mostly on 20-acre spacings. It's also been helped by the fact that PVR's Crossroads plant has just recently come online and are now getting credit for the NGL volume. That will become more apparent in the third and fourth quarters.

The first of those Lower Bossier or Haynesville wells, the Fogle #5, as I said we announced that well, continues to produce pretty much as we would have expected and has 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 grow 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 completed. 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 #8, as I said, is about 2 miles away, which should be finished off by the end of August. Baird can obviously put some color on this, but I think what he shall say is it appears to be performing like the Fogle #5, but we don’t know and won’t know until we’ve completed it. And certainly the Mackenzie 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’d 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 7 rigs running in East Texas and either 3 or 4 of them committed to the Bossier.

In the Midcontinent, 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 of wells into the horizontal Granite Walsh which has been very prolific, some Hartshorne Horizontal CBM wells and of interest to us is that we drilled or participated in three Horizontal Bakken Wells in Dunn County in North Dakota. 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. And importantly, the second operated well is making about a little over 650 barrels a day, which is a very good well and we got another one in which we have very small working interest, but again data – this is 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 in perspective, and I’m going to say that 60% of that we would consider to be prospective and the other is to be determined, but we were not holding out a hell of a lot of hope for it.

The Horizontal Granite Wash wells have as I said very pleasing to us, having IP rates of 12 million a day and 14 [ph] on the other. We’re now anticipating on a net basis drilling between 9 and 10 of those wells this year.

Likewise, we’ll ramp up our Hartshorne Coal activity this quarter and bring on a third rig sometime in August. And lastly in the Midcontinent, 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 million, 6.4 [ph] 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 may recall, we’re switching over to a horizontal program there. Those wells have been quite prolific, but as a result of switching over and 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 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 and we don’t know yet what it’s going to tell us. We’re testing that as we speak.

Appalachia production was actually down compared to a year ago quarter and up a little bit over the first quarter of 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 got three wells drilled with two additional wells expected later this year. We’ve 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 and that will be done also on the second half of this year. And finally in the East, in the Marcellus in Pennsylvania and New York, we have around 21,000 acres, which doesn’t make a real big player over there. We got into the play a little 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. So, we’re trying to pick our spots where we think the sweet spots of the Marcellus may be and we probably won’t test any of that this year or the early 2009 before we get going there. And we’ve 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, they are commencing those development programs in what we call Bayou Postillion 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 LLC, 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 affected by non-cash hedging expense. The 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 it was averaging about 190 million a day.

Gross margin is at $1.34, very strong and 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 royalty is at 358 or 320. If you subtract out operating expense, we are well above the 298 we got last year and the 314 we got it in the first quarter, after reflection of some more additional net coal coming off of our properties as well as coal prices going up sort of across the board.

Looking ahead, we would expect PVR particularly because of the acquisitions we made in the first half of this year, 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 PVG's announcement that as of the 20th of August this year, it’ll 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 20.5% 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 –

Baird Whitehead

That’s fine.

Jim Dearlove

Okay, then Frank, if you could take us through capital resources, derivatives, and guidance?

Frank Pici

Sure, Jim. Good afternoon everyone. I’ll do it in 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 state the guidance in capital resources.

On the derivatives side, you saw in the income statement that we had large mark-to-market expense for hedging in the quarter, almost $104 million. About $74 million of that was from the oil and gas business, another $30 million from the midstream business in PVR. And of course, we'll give you some adjusted net income numbers as well to adjust out the unrealized noncash part of that and just give you the cash portion on several [ph] 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, with less than $1 million. So, that just illustrates the volatility based on the strip, and how that strip changes. So, of course we – that’s one reason we believe that this adjusted net income calculation is relevant and that it gives you really the cash impact of the hedging program.

Similarly on the midstream side, these positions changed as well, not quite as significantly. I think they went from mid $30 million, so I think they were about $38 million at the end of June to about $27 million in 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 or near or at record, I think they were record prices for natural gas physical sale. We realized pre-hedging prices of about 11.24 an Mcf. When we take and factor in the settlements on the hedging side, we gave about $0.80 of that back so we – post hedging realized about $10.44 an Mcf, still very high and of course the fact that we have this high prices in these high hedging settlements are just reflective of the physical markets we had for the second quarter.

Similar to that, and of course the revenue is not quite as high of a contribution as natural gas, but on the oil side, we gave back about $263 a barrel, off of it $121.54 physical sale price on the oil side as well, but again very high realizations. Looking forward, based on current production levels for the rest of 2008, the second half of 2008, we are about 53% hedged. We’ve got a cross-over of various natural gas hedging positions and by the way, most of what we have hedged is not always natural gas now. The average floor price is $8.38, the ceiling is $10.06.

Going into 2009, we currently have about 30% of current production hedged at about 8.75 by $11 collar. We have some positions into the first quarter of 2009 and that is about 20% of our current production for the first quarter of 2009, hedged at 9.30 by 13.45, so I think they are very healthy hedge positions going forward and I think those will help support our cash flow needs for our capital spending program.

Switching over to guidance for a minute, and then I will get into our capital resources, if you will 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, narrow the lower end of our gas production guidance, natural gas, and oil production guidance slightly.

We did show an expected improvement and will continue in our operating expense category under oil and gas. We tweaked our DD&A or depreciation, depletion and 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.

The most significant change in oil and gas was in our capital expenditures program. We have increased that by $135 million to $140 million over our previous guidance. The three main components of that were our drilling programs. In our development exploratory drilling, we’ve got as Jim mentioned a minute ago more wells. We got 15 to 20 more net wells planned than we had in our previous guidance. The biggest component of them are in the Lower Bossier, Haynesville play and in the Granite Wash and Bakken plays in the Midcontinent.

We’ve also got some additional well drilling in our Selma Chalk program, a little bit of that is horizontal drilling. And there is also some inflation built in there for drilling costs. So those are the main drivers for that increasing guidance on the drilling side. As Jim mentioned also, we have increased our guidance for our leasehold acquisition spending. That again is primarily in the Haynesville/Lower Bossier area, and to a much lesser degree in the 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 & 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 began – refined our ranges a bit on the coal side and in the midstream side, we have increased our coal realization as a function of the higher price realizations that PVR (inaudible) are seeing in their coal sales and otherwise updated the guidance for capital spending for known acquisitions that we’ve made and some organic spending in both of those segments. So with that said, that’s pretty much all the guidance.

Just to 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 has 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 and into ’09.

The reason it went down between June and early August was that we had sold some PVG units, we sold a couple of million units out of the position we had there, we 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 leasehold 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.

Jim Dearlove

Okay, well thanks Frank. Let me just sum it up and then we’ll take whatever questions you might want to ask us. We said in the release and you got from the tone of both Frank and I employed that PVA had, we think, had 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 the Midcontinent, which kind of get lost sometimes in all of these shale hype, it’s not hype but it’s excitement, let me call it, is just very solid and we would expect that the shales that we’re involved in, the Haynesville, the Bakken and the Woodford, Lower Huron, ultimately the Marcellus will only add to that.

We’re quite encouraged by the way the company is positioned, and as Frank tried to just tell you I think on 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 through PVR is very well positioned and I kind of gave them a short script here today, but I would remind you that if you go to pvresource.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’ll be posted, but we had a 45 minute call here earlier today with some very good questions on it, and Ron and Keith both had a chance to give their views on their respective operations. And so I’d encourage you if you’re interested to go and listen to that.

So in short, I mean, regardless of the extreme and to me often indecipherable volatility in the equity market, 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.

Question-and-Answer Session

Operator

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

Scott Hanold – RBC Capital Markets

Good afternoon.

Jim Dearlove

Hi, Scott.

Scott Hanold – RBC Capital Markets

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? And then have you learned – what have you learned from your drilling and completing that well, and have you acquired anything differently to your subsequent well that you're drilling right now?

Baird Whitehead

Scott, that well is making right now – it’s essentially floating our line pressure about 500 tons. It’s making about 3 million a day but – I don't want to call it strange, but it is ironic because that well has essentially stabilized at that rate. I’m not going to say there is not still 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 rates at the end of almost two months now, it’s very easy to extrapolate to these kinds 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 at least based on some of the drilling indicators that we’ve seen on the Brown well and even recently on the McKenzie 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 Brown well. We, of course, not only because of additional frac stages, but because of each individual frac stages dealt, we will put more sand away per stage. One thing we’ve also learned and we think to some extent it may have a negative effect on the Fogle, is we shut that thing in for about two weeks right after it had been on line for two to three weeks. (inaudible) in those inflatable fracker systems that we utilize to do the stage jobs, the frac stage jobs. Probably, on the Brown, going forward, we’re going to go ahead and get those fracker sleeves drilled out immediately to keep that thing flowing after the frac, because we pump a lot of water away in these things. We think once you get these things flowing back, you need to keep them 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 about it.

Scott Hanold – RBC Capital Markets

Yes, I know. 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 are reasonable and if you look at it sort of to follow and understanding, this obviously have been shut in for a period of time which could have impacted the rates, but based on what it is doing right now, is it meeting or exceeding your sort of internal model?

Jim Dearlove

I would say it’s exceeding what we internally modeled this thing going into it, yes.

Scott Hanold – RBC Capital Markets

Okay. Thank you. And Frank, on the balance sheet, it looks like you guys are pretty well setup to take on the extra spend you have this year. What are your thoughts in 2009? And I guess this is 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?

Jim Dearlove

Let me answer that. We have, as it’s 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 if it is sustainable in the long term. We sold, as Frank said, we sold a little bit of PVG, although I would not call it non-core, that will still help augment an acquisition frankly that TDR made. So we need to 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 are not going to let our balance sheet get out of whack. If we have to sell something because we are getting a better return, let’s say the McKenzie takes off, we’ll do what we have to do.

Scott Hanold – RBC Capital Markets

Okay. So would the preference be to look at parent dominant asset base versus stay and looking at the capital markets to sort of, in mid ’09, you really felt the need to accelerate?

Jim Dearlove

I've noticed that you had a price on (inaudible) 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 heads, Scott, to re-access the capital markets.

Baird Whitehead

Hey, Scott. Just to reiterate what Jim said is, I think it’s really a combination of things between – we’ll see what equity markets look like next year and what opportunities we have in front of 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, unless there is some sort of a melt-down in the banking markets overall, with a 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.

Scott Hanold – RBC Capital Markets

Right. I appreciate it. Thank you.

Baird Whitehead

Thank you.

Operator

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

Steve Berman – Pritchard Capital Markets

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

Baird Whitehead

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 to be a pilot hole down through that interval and see what we have. But we have no information whatsoever on our leasehold as far as what potential the horizontal may hold.

Scott Hanold – RBC Capital Markets

What did you say your acreage up there is now – total acreage?

Baird Whitehead

If you talk about it in total, we've got over 60,000 net acres, but it’s probably 15,000 acres of that that we think have 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.

Scott Hanold – RBC Capital Markets

Okay. Moving to the Haynesville/Bossier, your joint venture partner in their release said that they expect TVOG 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?

Baird Whitehead

Yes, I mean, (inaudible) what we’re going to do in Haynesville this year. But I’d say, based on the AFEs that we have sent to GMX, that’s realistic. I'd say most of our activity is going to be on 100% acreage.

Scott Hanold – RBC Capital Markets

All right, thank you.

Baird Whitehead

You're welcome.

Operator

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

Irene Haas – Canaccord Adams

Yes, one more question on the Bakken, you said 29,000 net acres, that’s a 60% that looks prospective, right?

Baird Whitehead

Really, Irene, we think probably – we have been very conservative as far as what we think we have there. We think that probably more than 60% is prospective; I can say either probably out of the 29,000 we have based on one well we drilled that didn’t perform, it’s probably only 4,000 or 5,000 net acres that we'd say probably have been condemned. So that leaves 24,000 to 25,000 net acres that still could be prospective in the Bakken in that overall area, which is more than the 60% of course, but we have got to get more wells drilled and we just approached this conservatively at this point in time as far as oscar [ph] locations we feel real strong about.

Irene Haas – Canaccord Adams

Okay. While you started the year, in the beginning of the year, you were going to drill two wells in the Williston Basin – obviously you upped your retail. What could we look forward to next year and what are your major decision point that you're going to go in and treat like a development project? How does the Williston rank within your – is it really healthy portfolio like a number two or number three?

Baird Whitehead

I'd say it's right up there. I hate to rank something just one time; considering oil prices of course, it's right up there. Our plan going forward is to go ahead and keep up the development programs. In a lot of areas, we're having a hard time finding a rig at this time. We have already committed to a new build. It will 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.

Irene Haas – Canaccord Adams

Thank you.

Baird Whitehead

You’re welcome.

Operator

The next question is from Bob McDorman with Investment Counselors of Maryland. Please go ahead of your question.

Bob McDorman – Investment Counselors of Maryland

Jim, how‘re you doing?

Jim Dearlove

How are you, Bob?

Bob McDorman – Investment Counselors of Maryland

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

Jim Dearlove

What do you think on the Haynesville?

Baird Whitehead

Well, since most of the acreage we have in East Texas was prospective when the Haynesville was acquired because we had Cotton Valley potential mineral sites. We look at incrementally as far as Haynesville goes, rates of returns on those wells are very, very high. So to answer your question, $8, Haynesville based on how we have the thing modeled at this time still clearly lies with those kind of process.

Jim Dearlove

The first part of your question was would you have up this budget as much as if gas prices we’re $8 bucks and you are comfortable if 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. Just to refresh your memory, we have drilled, I believe the number is, 15 vertical tests on our fifty odd thousand acres. It’s up to about 60,000 now. And we’ve seen that, the Upper and Lower 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 an acre. And when we leased it, we were leasing the Cotton Valley not the Haynesville. So, the numbers would have changed, but I think the philosophy wouldn't.

The fact that Haynesville worked, the fact that Lower Huron is working, the fact that we think we are learning a little something maybe this early 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’re all working and so we – in some senses, have an embarrassment of riches. We surely would have taken advantage of them no matter what the price of gas was. It was $6 when we thought it was going to stay there forever, which we don’t.

Bob McDorman – Investment Counselors of Maryland

Okay, thanks.

Jim Dearlove

I hope I answered you.

Bob McDorman – Investment Counselors of Maryland

Yes, thanks.

Operator

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

Biju Perincheril – Jefferies

Hi, good afternoon. Baird, I think in the Fogle well, one of the frac stages was located in the Upper Bossier section. Is that what you plan to do with the Brown well as well or is that going to be all in the Lower Bossier?

Baird Whitehead

Probably that last interval will also be in the Upper Bossier, Biju, just because we picked up a tremendous amount of gas as we drill off in one of in Cotton Valley. In 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 as we (inaudible) start increasing your mud ways in order to control the (inaudible) move probably in all likelihood complete that upper Bossier in that last stage.

Biju Perincheril – Jefferies

I think you had – initially you were planning on putting one well entirely in the Upper section. It's my understanding (inaudible) all your plan or –?

Baird Whitehead

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.

Biju Perincheril – Jefferies

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 –?

Baird Whitehead

No, we feel it's a geological issue. The Bakken works because it’s a dolomite and we (inaudible) our first well. It appears that majority of the holes in the latter was not a dolomite. In fact it was actually a limestone which impeded production because it’s extremely tight. So, yes, the answer to your question is geological issue.

Biju Perincheril – Jefferies

Okay. So then does that condemn the acreage to the lesser cut well or I guess that well is on the sort of the Western of your acreage there, correct?

Baird Whitehead

Well, 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.

Biju Perincheril – Jefferies

Okay. And you said that's about 5,000 or 6,000 acres?

Baird Whitehead

It's about 4,000 or 5,000 net acres. Yes.

Biju Perincheril – Jefferies

Okay. Thanks. That's all I had.

Baird Whitehead

You are welcome.

Operator

(Operator instructions) The next question is from David Snow with Energy Equities Incorporated. Please go ahead with your question.

David Snow – Energy Equities Inc.

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

Frank Pici

It’s about 3 million. If prices went to infinity, it would still give about 3 million new shares issued.

David Snow – Energy Equities

Okay. And it sort of goes on a straight line from here to there?

Frank Pici

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

David Snow – Energy Equities

Okay. All right. Great. And in the Bakken, can you give me an idea of how many stages you’ve been fracing?

Jim Dearlove

David, we've two wells – the second well because the first well is not a good data point geologically. The second well, we did nine stages in it.

David Snow – Energy Equities

And how long was that?

Jim Dearlove

It was about 9,000 feet.

David Snow – Energy Equities

Okay. And you had a third well also, what was that? Or you have small interest in the third well?

Jim Dearlove

Yes. The third well, we had a small interest in but it was also about 9,000 feet.

David Snow – Energy Equities

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

Jim Dearlove

It’s about 4,000 feet.

David Snow – Energy Equities

And how many stages?

Jim Dearlove

We plan on doing – we did seven stages on the Fogle well. We plan on doing eight stages on the Brown well.

David Snow – Energy Equities

Okay. Thank you very much.

Jim Dearlove

You’re welcome.

Operator

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

Richard Tullis – Capital One Southcoast

Hey, 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’ll do?

Baird Whitehead

I think it’d be premature for me to answer that question, Richard. Before we start throwing numbers out here, we need to get some more production history under our belt. It would be my preference to leave at that at this point in time.

Richard Tullis – Capital One Southcoast

Sure. That’s fair enough. What’s your average royalty on your total Haynesville exposed acreage?

Jim Dearlove

It’s about I think 80%, a little bit north of 80% would be an accurate number. The new releases we picked up here recently because of the Haynesville are a quarter [ph] that allow the earlier releases we have picked up with GMX or outside even the GMX, with Cotton Valley and in mind, we have anywhere from 80% to 85%. So I’d say about 80% is a good average.

Richard Tullis – Capital Once Southcoast

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

Jim Dearlove

The larger ones – I need to stand upon the good one that we drilled. We have yet to get in there and drill out those fractures through [ph] and we think that can affect about a few hundred barrels a day.

Richard Tullis – Capital One Southcoast

Okay. And last question, what’s your current total production?

Jim Dearlove

As we speak?

Richard Tullis – Capital One Southcoast

Yes, if you got it.

Jim Dearlove

135 is about right.

Richard Tullis – Capital One Southcoast

Okay. That’s all from me. Thanks so much. Appreciate it.

Jim Dearlove

Thank you, Richard. You’re welcome.

Operator

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

David Snow – Energy Equities Inc.

Yes. I wondered if you could give us a guess and put a per section estimate for your Haynesville, Lower Bossier, whatever?

Jim Dearlove

The Lower Bossier (inaudible) we’re utilizing about a hundred Bs in place per section. We assume that 20% of that is recovered as 20 Bs per section. Take it across our leasehold, I realize it’s a good guess at this time. I can see we've only got one data point on our belt. We have at least probably one-and-a-half Ts of net reserves; based on our acreage position that would be on the lower side. That does not include the Upper Bossier by the way also.

David Snow – Energy Equities Inc.

How much would it have if you included the Upper Bossier?

Jim Dearlove

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

David Snow – Energy Equities Inc.

All right. Are you the only one that’s appropriated in the upper Bossier along with the Lower Bossier?

Jim Dearlove

I can’t answer that question, I do not know that.

David Snow – Energy Equities Inc.

I haven't heard of another one doing that. It sounds like you’re front on that, doesn’t it?

Jim Dearlove

I think we’ve got probably a slight different geological issue between the North Louisiana (inaudible) what we’re seeing over our way.

David Snow – Energy Equities Inc.

You have – it separates out more in your side than on North Louisiana?

Jim Dearlove

I’m just speculating at this time.

David Snow – Energy Equities Inc.

Okay. Thank you very much.

Jim Dearlove

You’re welcome.

Operator

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

James Dearlove

Thank you, Joe. Thank you those of you on the line. The queue says there is 60 some of you and I am sure there is 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.

Operator

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

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