Ranger Oil Corp (ROCC) 2010 Q2 法說會逐字稿

Good day everyone, and welcome to the Penn Virginia Corp's second quarter 2010 earnings conference call. Today's call is being recorded. At this time for opening remarks and introductions, I would like to turn the call over to Mr. Jim Dearlove, President and CEO. Please go ahead, sir.

Thank you and good afternoon to all of you. I'm joined here today by speakers Baird Whitehead, who is the COO of the company, and Frank Pici, who is the CFO of the company. They'll do the heavy lifting and I'll just do some introductions here, I guess. This conference call is unusual in the sense that it is Penn Virginia's first call as a pure play E&P company. As customary, we'll walk you through the highlights of the second quarter release and the operations release, both of which came out last evening. But before we do that, let me just give you a quick overview of the company as it stands today.

PVA sold the last of its PVG units in June of this year. And although there's some ongoing transition activities, and you saw a hit to G&A due to some of that, and things like information technology and that sort of thing, haven't completely switched over. For all intents and purposes now, Penn Virginia is completely separate from PVR and PVG. As we go forward, it's our intention to take advantage of our strong liquidity position, and we're going to try to do that to move Penn Virginia forward in basically two ways. As you may know, in the last 12 months, including the sale of the PVG units, we've raised about $850 million and for us, that -- puts us in a pretty good liquidity position, which Frank will elaborate on when he gets to. At any rate, we intend to accelerate our growth in the liquids rich Granite Wash and in the horizontal Cotton Valley plays. And we're also going to seek to judiciously add to our core plays, particularly in the Granite Wash and the Marcellus shale.

We believe we can achieve growth in production this year, as well as the strategic positioning in those plays, without in any way compromising our financial flexibility. In fact, we expect to end 2010 with nothing drawn on our revolving credit agreement. To be a little more specific, as it says in the release, we've raised our midpoint CapEx guidance by 17.5% or $70 million to $470 million. And this number is as broken down for you in the release includes $325 million to $350 million for drilling, two-thirds of that in the Granite Wash and the horizontal Cotton Valley. That CapEx number, that total number, also includes $100 million to $110 million, our best estimate at this point for acquisitions. Some of them, of course, have been made. And this is leasehold acquisition. About 85% of that is targeted towards either the Marcellus shale or the Granite Wash.

Looking back at the release for a minute, as you can see, 2010 second quarter production was 10.5 BCFE, which was lower than it was in the corresponding quarter of 2009, and slightly ahead of where we were the first quarter of this year. The quarterly year-to-year production was down as you might -- as we would have expected because if you recall, we suspended drilling in the second and third quarters of 2009. So, the effects of those natural declines are now evident in our statements as we try to catch back up. We were off by about 0.7 of a BCF from where we expected to be for the quarter. And the culprit there primarily was something that we actually talked about last quarter, which was delays in well completions in East Texas in particular, and to the Granite Wash to some extent. Those delays were caused by the difficulty we had in obtaining stimulation equipment for these wells. That problem in East Texas has been addressed. I think we put out a press release on that in the middle of the second quarter. But it certainly had its effect, particularly in April and May.

As it says in the release, by June we were -- we had completed some wells and, in fact, our June production was 133 million cubic feet equivalent per day, which is one of the best production months in our history. Baird will get into the details of the operations, and Frank will cover the financial aspects of things. I might just point out one thing, try not to steal anybody's thunder here, but we do expect, speaking of production, that our second half production will be anywheres from 24% to 38% higher than it was in the first half of the year. In the release, we also discussed the pricing we received for gas, oil, and natural gas liquids in general. Second quarter 2010, prices were higher, considerably than they were in the second quarter 2009. Gas, the driver, was up about 22%. They are also quite a bit lower than they were the first quarter of the year. Again, gas was down 20% plus quarter-to-quarter.

We do some hedging that Frank will probably touch on. About 50% of our second half gas production is hedged with collars. The floor is $570 [million], the ceiling, if you will is $785 [million]. I guess the last thing I might mention before turning it over to Baird is we did experience an operating loss in 2010 second quarter of almost $21 million. We call this an improvement over 2009. It's hard to think of it as an improvement, but it is better than the disastrous year that most companies had in 2009 second quarter. It's not as good as we did in the first quarter of the year, and that's primary low prices. Production was essentially flat, prices were considerably lower, and we had some G&A activity, again, about $4.2 million that had to do with the restructuring or the sale, really, of PVG. So, with that, I'll turn it over to Baird to talk about operations.

All right. Thank you, Jim. I'll go ahead and go through each play type like I typically do, and start off with the Granite Wash. As we had in our press release, we drilled 12 gross and 5.6 net Granite Wash wells in the second quarter. And of those, we have completed 9 gross and 4.3 net. Our total completion activity in the second quarter was 10 gross, and 3.5 net wells. So we had -- we had some wells in the first quarter that were actually completed in the second quarter. And as of right now, we still have 7 gross and 3.8 net wells that are waiting on completion. So, we still have a backlog of wells to get completed. In the second quarter, Penn Virginia completed two operating wells, that being the Deborah Jean 2-6, and the Gudgel 1-6. Those wells had respectively 19.2 and 11.1 million a day equivalent, which included NGLs. If you are only talking about wellhead IPs, we're talking about 15.5 and 8.9 for those two wells.

In addition, there were eight Chesapeake operating wells that were completed with IP rates of -- with the lifted numbers here of 9.7, 8.9, 1.4, 12.3, 16.5, 16.7, 11.6, and 18.1 million a day equivalent, which, again, includes the uplift because of liquids. We did sign a processing agreement as of June 1st. Right now, we model our Granite Wash flow and average Granite Wash well with 85 barrels of oil per million at the wellhead recovered. And with the processing agreement there's an additional 80 barrels per million based on inlet (inaudible) to the plant. So, we now model a typical well with 3.6 BCF of residue gas. About 350,000 barrels of oil recovered at the well. An additional 330,000 barrels of NGL. So, right now our typical gross Granite Wash well, 7.6 b's. Prior to that processing agreement, our average well was about 6.2 b's. So, with that processing agreement, there's been a 23% increase in gross reserves as a result of processing.

Right now, Penn Virginia has four rigs drilling in that play. Chesapeake also has four rigs. So, you can see we are extremely busy. We have two operated rigs within (inaudible). Chesapeake has three rigs drilling. In addition to our three rigs drilling in exploration and Granite Wash prospects, one of those we talked about in previous quarters and is our operated Mountainview prospect in Caddo County. We have an 87.5% working interest in this first well. We've leased about 10,000 net acres. The prospect in total has a net unrisked reserve potential of about 430 b's. We are currently drilling a lateral as we speak in Granite Wash, and we expect to have some information on this well probably sometime in the fourth quarter.

We're also drilling what we refer to as our East Sayre prospect. This is the first time I think we've talked about this. This is located in Beckham County, Oklahoma and it's much smaller in size. It is an oil prospect. We have a 67% working interest in this first well. We have about five net acres in this project now. As I said, it's oily with a net unrisked reserve potential of about 135 b's. The one advantage of this smart prospect is we feel there's probably going to be multiple pays within the Granite Wash itself, and we are currently drilling the vertical part of the hole.

And lastly, there's an asset (inaudible) exploration well being drilled in Washita county. I think it's the first time we talked about this also. Referring to it as our Clyde Chief and Pyle prospects. It's actually two adjacent prospects. We have a 28% working interest in this first well. The two prospects in total have a net unrisk potential of 170 b's, and we have about 4500 net acres in this prospect and continue to lose. So, as far as activity and that, they have just set intermediate casing. We'll be drilling out to drill our curve and to subsequently drill our lateral. And for the remainder of the year, the exploratory front, we do plan on drilling a second well in my view.

And we have at least three, four more wells to drill in Clyde Chief and Pyle prospects, and possibly one other additional Granite Wash prospect will get drilled. For the year, we now expect to drill in the midcontinent 60 gross wells and 24 net wells. Most of those of which, of course, are Granite Wash wells. In East Texas, even though we are still behind in completions in the beginning of the second quarter, as the second quarter went on and up until the first part of the third quarter, we have been busy fracking the inventory of Hazel wells we had -- as we reported previously, we had signed a one-year contract with C J that provides our pumping services for a year in both East Texas, with the option to take it to the Granite Wash if need be to frac those wells. Since we restarted our Haynesville program at the end of last year, to remind everyone, we had drilled six gross wells.

To date, four of those have been completed. We did have one well, we had a casing problem on after we completed fire frac stages and the sixth well is waiting on completion. Tentatively it will be fracked sometime in September. The four wells completed include the [Bryant] 6, the (inaudible) 2H, the Timmons 3H, and the Tiller 1H. And those four wells had IP rates of 10.4, 15.3, 8.9, and 10 million a day respectively. The well in which we had a casing problem on, it is producing. It's producing about 2.4 million a day. That well has actually been on production now for about two months and believe it or not has not declined at all. It's just staying right there at 2.4.

As we pointed out on the press release, the Bryant and the (inaudible) wells were the first two wells that we could -- that we drilled and completed. Once we got back to drilling, the 30-day rates of those wells were 7.4 and 11.2 respectively. The Bryant well was fracked with 15 stages and the (inaudible) well was fracked with 24 frac stages. So we had put a lot more frac stages away once we got back to drilling Haynesville wells. If you look at these two wells and the current production rate at the end of approximately 60 days, and you compare it to the previous two best wells we had drilled, were the last two wells we had drilled in 2009. But before we shut things down and had 10 frac stages put away, these first two wells out of the bluffs this year are actually 75% better at equal points in time.

In fact, the Bryant well has already made about a half a BCF in three months and the [Fults] well, which is clearly the best well we have drilled so far has made about a half a BCF in about two months. So, they're both very, very good wells. The Timmons and Tiller wells are the other two wells we have completed, are also doing very well. They're producing 8.3 and 9.5 respectively after being online in a little less than a month. The Timmons well had 21 frac stages put away and the Tiller well had 17 frac stages. So what we have learned -- we have learned clearly that putting away more frac stages has improved the results. To some extent, we are also drilling longer laterals as we can.

We have also concentrated in the lower half of our acreage position, where geologically we think is the most attractive. And as we have stated in the past, we continue to hold back pressure on our wells. This does appear to be lessening, decreasing the initial decline rates, but if you try to weigh the additional frac stages versus back pressure, it's impossible to allocate what part of the overall improvement and well results is coming from each piece. But you would only have to assume that the additional frac stages is having more of an effect. The plan for the remainder of the year is to complete this last well that's not completed, our Anderson well.

We're going to continue to sit back and look at the results, and by the end of the year figure out economically if we can continue to make sense drilling Haynesville wells. But there's little question we have made significant progress and improving the results of our Haynesville wells in these last six wells drilled, four of which have been completed. For the rest of the year, we are drilling Cotton Valley. We have drilled two wells. We drilled the Gibson (inaudible), the McClendon wells. Those two wells had IP rates of 4.1 and 2.5 respectively. If -- if you include the NGLs, the rates of two wells were 4.9 million and 3 million a day.

After two months, the Gibson well, the first well we drilled and completed, it's still making 2.8 million a day and 130 barrels of oils per day for a total of 3.6 million a day equivalent, and that's wellhead. There has been very little decline in this one well since we turned it inline. In fact, if you look at the three-day rate, the seven-day rate, and the 30-day rate for that Gibson well, all three of those rates were essentially the same. What is also unique about this well is the quantity of oil that it's making. The oil percentage is much higher in this well than we have seen in any vertical well we have drilled. Typically, we use about 15 barrels per million when we model these wells. This well is making 50 barrels per million. So, it's over three times greater.

In addition, if you take into consideration the uplift, because of processing, this has an additional 60 barrels per million. The McClendon well, the second well, has been producing less in a month. It's making about 1.5 million a day and about 25 barrels of oil a day. The big difference between these two wells, the Gibson well, the first well, was actually fracked with 12 stages, with a lateral length of 4200 feet. The McClendon well, we only fracked with seven stages because the lateral length was only about 2300 feet long. So, -- and we think that's the most significant reason of why the Gibson well is a much better well. But any case, we are going to get some more information under our belt on the Cotton Valley, and continue to tweak the completions and the lateral lengths, and just like the Haynesville, sit back and see how we are doing. But in any case, based on what we have seen so far, we are very pleased. If we can continue to replicate like the Gibson well and see some higher oil rates, that's only going to add to the economics.

In the chock, we continue to drill one rig -- with one rig. We drilled four gross and 3.9 net wells in the second quarter. We continue to make things a little bit better there. We have cut our drilling days way back. Initially, these wells were taking about 21 days from spud to TD. We've actually got spud to TD down to 15 days. We continue to adjust the completion side. We are running a (inaudible) log as we drill the lateral to improve upon where we actually perforate the lateral. So in any case, we feel we continue to make some improvements in this play. Even though we don't talk about the chock a lot, and I guess most of us, we consider the results of this modest, we do consider this a key part of our portfolio. It's important to remember that the results are pretty predictable, and if you look at the much lower drilling and completion costs at about $29, and the fact that we have little operation risk as compared to drilling a Haynesville wells for instance, we feel it's important to what we do.

And lastly, in the Appalachian and Marcellus specifically, we had no activity in the second quarter. We originally thought we were going to have a drilling rig in place sometime in August, but we were notified by the drilling contractor that that rig, in fact, will probably not show up until late to third quarter, early fourth quarter. For that reason, we expect only now to get two horizontal Marcellus wells to be drilled. But we have been busy. We've been busy value to our leasehold position. We made a press release here a few months ago (inaudible) our partner, and to date, we have about 58,000 net acres in this play. About 36,000 in acreage in Potter and (inaudible) Counties. So we have a nice position there. If you remember at the end of the first quarter, we had about 45 net acres. So we've added 18,000 net acres, and most of those acres added has been in this Potter and (inaudible) County area. So in any case, what's that Jim? Turn it back over to you.

Thank you. It's very thorough, as always, and Baird is clearly enamored of Mississippi and we keep trying to get him to call it the Soma shale, and I think we could get excited about it. At any rate, Frank, why don't you, if you would, take us through the capital and the financial issues.

Ok, sure. Thanks Jim, and good afternoon, everyone. I guess first I would like to make a comment about the revised financial reporting that you see in this release. It's a large change from what we've been showing you over the years, and we hope for the better. This is really a result of our sale of our interest in PVG and the -- and PVR, the other MLP. As you know, in June we completed that sale with our remaining limited partner interest. And then a related transaction, we relinquished control of the non-economic GP interest in PVG. But -- and as a result of those transactions, we recognized a gain from discontinued operations of almost $50 million net of taxes during the second quarter, and you'll see that on the income statement. But maybe as important, the sale allowed to us present our results as a pure play E&P company, both going forward and with our historical results. We've taken the PVG, PVR results which previously have been included in our -- in our financials, and shown them as discontinued operations. We think that's a very important step to us in terms of making it more -- making it easier, if you will, for investors to understand our story and hopefully stimulating some interest in us.

At least we've cut our press release down from 14 pages to 10. We hope that helps a bit, and we hope you appreciate the revised disclosure. I guess a word or two about hedging, as Jim mentioned. We -- we do have for the second half of this year, 50% of our estimated production hedged at a pretty healthy floor and ceiling, 570 by 785, which is well above the August 3rd strip for the second half of about 479. For the first half of the year, we collected almost $18 million in hedge settlements, which improved our realizations on natural gas by over $1. As we think that's been good effect for us.

Going forward from 2010 and 2011, we've got about 32 million a day on average hedged at about 570 by 820. That quantity decreases by quarter, and then into 2012, we placed some base level positions through the third quarter, again, declining quarter-by-quarter, but again, but at very healthy floors and ceilings. Looking at our capital resources and liquidity, as Jim mentioned. With the transactions we have had over the last 12, 15 months, we've got a very healthy capital structure. We've got over $315 million of cash on hand, plus a fully available credit facility. Current commitment on that is $300 million, but we can actually take it to $420 million per our borrowing base if we chose to. With our current CapEx plans, of course, we would exit 2010 with plenty of dry powder, and we think that would carry us pretty far into 2011, perhaps all the way through at current spending levels. So, again, the capital structure is very sound.

Just a quick update on some of the guidance. You'll notice as we talked about production, we didn't make any change to our full year guidance, but we did increase Q3 and Q4. There's been some switches between the products. I think net gas was decreased very slightly and NGLs were increased somewhat as a result of the new processing arrangement we've got in the midcontinent. On the operating expense side, we've shown more detail than we've been showing the last several quarters. With our conversion to pure play E&P style financials, we chose to show you a little more detail for LOE and gathering and processing and production taxes as opposed to putting them together as we had been doing. For example, in LOE, we would expect there to be some improvement in the full year estimates there versus what you see for the first half actuals, and that's really a function of increased volumes, helping to better cover our fixed cost component of LOEs. So you'll see that on a per-MCF basis that'll improve. Our gathering and processing, however, will remain relatively flat on a per unit basis.

Production taxes will be up, if you look at second half versus first half, and that's really because the first half benefited from a -- credit we got in the first half of the year, the -- steady state production tax rate has gotten the guidance going forward. For G&A, as Jim mentioned earlier, we had a restructuring charge that increased our G&A in the first half, really in the second quarter, really as a result of our back office separation between PVA and PVG&R. Going forward, we'd expect the quarterly run rate in the $10 million to $11 million a quarter range for G&A. We think that's a reasonable run rate. And when you look at the other categories, exploration, we've -- we've beefed up a bit. Our prior guidance was $35 million to $40 million. It was beefed up $42 million to $46 million.

It's really a function of the increased capital spending, primarily for seismic costs and some -- there's usually some risk dry hole expense in there as well. DD&A is just down just slightly to reflect successful drilling and our -- the last thing on guidance, before CapEx, is interest expense. In the press release guidance, that's $45 million to $50 million. That's a bit light. It should really be $50 million to $53 million. We had a slight error in the guidance table. The cash component of that number is about $42 million to $43 million, with the rest being the amortization of fees and original issue discounts from our convertible notes and our high yield debt issuances. With respect to CapEx, I think we've pretty much already covered that, the mid-point of the guidance was increased to $70 million and Jim and -- both Jim and Baird have talked about what we're doing there and how we've dedicated some portion or redeployed, if you will, some portion of our cash balance towards these projects with the very strong returns in the Granite Wash and then also positioning for growth in places like the Marcellus. We think that's a reasonable redeployment of part of the cash. That's really, Jim, I think all I had on guidance.

Thank you, Frank. Again, very thorough, I thought. Well listen, before I turn it over to questions, I began this teleconference by saying that this was our first one as a pure play E&P company. Let me say it as a management team. And you've heard from three of us, but several others are in this room right now. And as a group, we're excited to have a single focus and a single purpose, and certainly we recognize there's challenges ahead for the company, and indeed for the entire E&P industry. However, we believe that Penn Virginia is very well positioned, as you just heard really from Baird and Frank. Each in their area of expertise, and very well positioned in terms of its asset base, its financial strength, and I'll say in terms of the high quality of the team of employees who make up the -- this company. So, we look forward to the future with a healthy respect for the challenges that we'll face, but also with the confidence we'll continue to meet them head on and successfully. So with that, I'd turn it over to questions now.

Thank you very much.

(Operator instructions)

And our first question comes from Brian Corales from Howard Weil.

How are you doing, guys?

Good, how are you?

Good. A couple of questions. One, on a go-forward basis, what is -- and you could use kind of rounded numbers, because there's a lot of leasehold, I guess, going for 2010, how does that look in the out years in terms of allocation of capital and what that gross amount is. Are we talking about a $400 million run rate budget, or is it more in the $350 million range? How should we think about that in the out years?

Well, we don't -- we have not put out 2011 guidance yet. So, I don't want to say nothing of 2012 when you ask a multi-year question and Frank or Baird, feel free to jump in here. Our guidance, midpoint guidance right now is $470 million and I think that's probably a -- not an unreasonable number to expect going forward over the next few years.

Okay. And looking at allocation, is it going to be roughly about 40% to 50% going to the Granite Wash likely, if the current commodity --

No, that's a -- I'm sorry, I didn't mean to cut you off. But you heard Baird say a number of times, for example, in East Texas that we want to make sure that we're understanding. I certainly think that we are by the progress we are making, whether that's the -- the Haynesville is a play you want to drill in a $5 environment. Clearly we've got better results, but they're more expensive wells and so you want to figure those things out. The Granite Wash we like right now. Who doesn't? Because of the oil component, it's almost -- I guess a little more than a third oil and a fair amount of NGLs. So, we like that. We'll do as much of that as we can.

You heard Baird talk about Mountainview and East Sayre, two experimental -- or I should say exploratory activities that we're involved with. Chesapeake is certainly very active, and we are partners with them. And South Clinton and some of the extensions thereof. I can't get into names and places because we're still leasing, but we've got several other ideas in the Granite Wash. We'll chase the Granite Wash as hard as we can. The horizontal Cotton Valley because of the liquids component, we're liking that. But your question was well how much leasehold? And that's a question of opportunity. We -- at 58,000 acres, I don't think we think we've got enough of a position in the Marcellus as you know, probably better than I, that's becoming a very expensive place to play and we're not going to go paying $10,000 an acres to play there. But we'd surely like to build that up. We would build the Granite Washes as opportunity presents itself, and we may have some other ideas. So, I think you'll still see some leasehold activity, yes.

Okay. And then one final question. With the -- I think it was a 24 frac-stage well in the Haynesville, it looked like the rates were much better. Can you maybe talk about the costs that you saw there, and -- did you see better returns so far or is that not optimal at -- or whatever you all are seeing with that well so far.

Brian, the cost of these higher number of frac stages, anywhere from $18 million to $22 million average. (Inaudible) at least up until we discontinue the Haynesville, it's about $11 million. I mean, it's a big number. The frac jobs themselves, because of fracking costs going up, become more of a material cost to the overall well economics, and you end up having $5 million to $6 million tied up in -- on the completion side. But having said that, those first two wells we drilled, we've made a half a BCF at both those two wells between two to three months, which are much, much better than anything we have drilled to date. And you can look at that early time information, and one of the wells you could put a range of anywhere from 6 to 8 b's. The other well you could put a range of 8 to 10.

Now, you've got to remember, these are very early time info, so we all have to be careful here, but -- and with $11 million cost, if you want to take the midpoint of that range, you can generate in a modest gas price environment, oil price environment, someplace between 15% and 20% after tax rate of return. But, the proof in the pudding is for us to get some more production rate information under our belt, and continue to look at this and see if these wells continue to outperform. But we're seeing these wells are actually flattening. Not only the rates are, but the decline rates are a lot less than we have ever seen. So, you're seeing we're fracking these things 200 feet apart along the lateral, the -- the drainage, though, that shale has to be much, much better, which is also having some effect on the -- on a decline rate. So, in any case, I've told you everything I know.

All right. Well, I appreciate that. Thank you.

You're welcome.

And our next question will come from Steve Berman of Pritchard Capital Partners.

Good afternoon guys. I'm moving to the horizontal Cotton Valley wells. I know these were your first two so they probably cost more than a normal rig. Can you talk a little bit about cost expectations there, and maybe anything more in economics, similar to the -- to the Haynesville questions Brian asked?

Steve, we figure we can drill these things for around $6 million, $6 million to $6.5 million, for about 5 b's equivalent, which generates around a 20% after-tax rate of return. And that's using a $4.50, $5, $5.50 and going to a $6 cap and keeping it flat after I think four years. But in any case, we've been -- and the oilier the better. As I explained that first well we drilled, we get some wells making 50 barrels per million wellhead, which is three times greater than what we had ever seen vertically. We drilled in a different part of the Cotton Valley, which makes you start thinking that maybe there's some more oil tied up in that part of the Cotton Valley. But again, we have to get some more wells drilled and see what we have. But because of the oiliness, you have to be encouraged, and we are at this time.

How much of your total East Texas acreage would you say is prospective for this? All of it?

I would say probably two-thirds to three-quarter. The northern most stuff, it tends to have a lot more water tied up in it. So you'd have to be careful. I wouldn't eliminate it. But it would just be lower on the priority list. That's all.

And overall production question. June was obviously a heck of a lot better than April and May at 133 million a day. Can you tell us what your current production companywide is running?

Well this would be an estimate. We don't have any actuals. July was about 140 equivalent.

140? Thank you. Heading in the right direction.

Yes, we think so.

Okay. All right. Thanks, guys.

Thank you.

And our next question will come will come from Joe Allman of JPMorgan.

Thank you. Good afternoon, everybody.

Hi, Joe.

Jim, you spoke about -- or I think you said it, Jim, maybe Frank, you talked about CapEx next year being roughly the same as this year. And I know you don't necessarily have a formal budget out there, but are you -- would that -- would that assume no drilling in Haynesville, or what's the assumption there?

We -- we assumed that we would resume drilling in the first quarter in the Haynesville. Baird tried to be very, I think, circumspect. And you heard why. At $11 million a well, you want to be sure that these returns that we're getting, which are more than satisfactory initially, can be maintained. So, we're going to complete that last one and -- and make sure that we're comfortable with it, but yes, I would anticipate that we're going to drill in the Haynesville, and the other half of your question, in a way is, well, if we have more success than we anticipated in the horizontal Cotton Valley and the returns are better, we may choose to focus there. Baird, do you want to --

Yes, one other thing just to add. We have yet to test the -- I guess nomenclature has changed now. We refer to it as Haynesville or the Bossier, which we referred to previously the Upper Bossier. In any case, whatever it is, we still think it has potential. We need to get a well drilled there. We have proven with the completion of that Bossier and some of our Haynesville wells because the Bossier is actually in the curve, that it clearly is making some gas, and if you can drill horizontally in that section, we feel even though it's a different animal that -- it has a lot of potential, and more and more of our peers are starting to talk about the Bossier also.

Joe let me back up too and add -- I didn't want to --I felt like I was sounding defensive or something in what I was saying. We've got so many opportunities. If things work in the Granite Wash that we're doing now, we're planned to do this year, if -- if the Marcellus -- we're going to only drill a couple of wells as Baird said, but if those results are -- better than what we're anticipating or -- there's just so many other things we're doing and we are not going to triple our budget or double our budget. I can't anticipate that we would do it. So, if there was reticence in my answer, it's because right now I don't know what the price of gas is going to be, and I don't know where the best opportunities will be. And that's certainly got to help guide how we spend our money next year.

And that's very helpful. And I didn't pick up any defensiveness at all. But just -- so, what are you thinking about in terms of the budget? So, if it's $470 million next year, then at least based on our model, you would be outspending cash flow by a pretty decent amount, and do you need to spend somewhere close to that to get a decent level of production growth? And -- but, of course, you don't want to just grow production when you get -- if the returns aren't there. But what sort of thinking about -- when you're thinking about the budget?

That -- this is Frank, Joe. That probably generates a fairly healthy production growth at that level because we're getting back on the growth trajectory with the projects we're drilling this year, and if we continue at that kind of pace next year, we'll see a pretty healthy growth then as well. I think where you start to see it flatten is a couple of years out, if you spend at that same sort of steady state rate. From a funding point of view, we've got -- as I said earlier, plenty of cash. We'd use of that before the end of this year, and then we'd start to get into -- probably start to get into the revolver at some point late in '11 in you were spending at the same rate, providing prices stay where they are at the strip today. So, I think we have plenty of -- plenty of powder to continue to execute that program without stressing the balance sheet.

That's helpful.

Joe, the models we run, again, we're not here to discuss price decks and that sort of thing. But we run all kinds of different scenarios, just like you do, of different spending levels and different assumptions. But almost invariably, the plans that we look at find our credit stats improving as we go forward in time.

Yes.

So if we outspend cash flow next year, would it surprise me? No. But are we going to -- as Frank just told you, are we going to put ourselves in an ill liquid position? No.

Sure. And then last one. So Baird, so let's assume that you actually don't do additional drilling in the Haynesville because the economics are not compelling, but you're still going to spend roughly $470 million. As of this point right now, which plays would you allocate more money to?

Well, to answer your question, if we didn't spend money in the Haynesville or the Cotton Valley, we probably wouldn't spend money.

No. We wouldn't.

Unless we had -- if you assume that we have some success in the Granite Wash, and these prospects we're drilling this year, we -- we would, but if -- if the economics don't make any sense for Haynesville and Cotton Valley, we would not have a $470 million budget.

The other wild card would be Marcellus, if we get things started up there.

Sure. Right.

Joe, I don't think we'd -- I think Baird said it pretty well. And if you look at our history in 2009, budgets be damned, we turned it off because we didn't like prices at all. And we didn't like the state of the economy. We didn't like anything. There's no magic to $470 million. I tried to answer a question that says this is kind of what we expect, but if things work out differently, if East Texas is not where we want to be, we probably won't spend it.

Okay. And what would preclude you from ramping up in the Granite Wash next year?

Opportunity. That's the only thing. We just got to -- Baird just told you Mountainview is 10,000 acres. If it works, we will ramp it up. East Sayre's smaller but oilier. If it works, we'll ramp it up. We've got, as I said -- at least -- you know me pretty well, Joe. I don't play games. We've got at least four other prospects that we want to stick a hole in the ground, and if they work, that's where we're going to go.

Got you. All right. Very helpful. Thank you.

With Global Hunter, Dan Morrison has the next question.

Real quick, back on the Haynesville. Have you done enough look-back economics to have a gas price in mind that you need to be above if I didn't miss that already? Before you would get excited about moving back in there with your current state of technology?

Well, based on the price deck I gave you, Dan, and the rate of return based on that range, the results -- we could have in the first two wells. And I think comfortably you would want to be north -- you'd want to be around $5 flat, $4.50 to $5.

Okay.

(Inaudible).

And are there -- do you all still have your acreage in the Bakken or Willisson basin? That was on the edges of the Bakken development, or is that all gone?

If we have any left at all, it's going to be gone and I think Baird is signaling that it's zero. No, we do not.

Okay. Thanks.

Thank you.

And Irene Haas of Canaccord has the next question.

Yes, my question has to do with Marcellus. Looking at all the play areas, obviously Granite Wash is going to give you some of the best return and some of the immediate gratification and multiple levels. My question is the Marcellus. How are you guys positioned in this particular play? And the -- counties you are in right now. In what way can you make it a strategic advantage, partly because the Marcellus is just so daunting in my view in terms of having to prove up each specific area, and then issues and following midstream, and generally it's a longer lead time project, even for the bigger firms. So, how are you going to play your Marcellus card?

Irene, that's a good question. It's a -- I'm not here to defend maybe what some people would view as slowness of us getting started, but we have the typical start-up problems with the play that's in full gear right now, trying to find equipment and rigs and stuff like that, but we'll get it done. We will get started. We do up in that Potter Tioga County that I mentioned, we've got about 36,000 acres. We continue to add to that. So, we've got a nice position up there. It's fairly contiguous and blocky. And we are in a fairly good position from a pipeline standpoint because of the storage fields in that area, and some of the big pipes like Tennessee and National Fuel and Dominion. So, it's just -- what we need to do -- we need to get in there and get a handful of these exploratory wells drilled across our acreage up there. Once we get comfortable with the results, then if we have to, we'll commit to the three-year term on rig or rigs, and just get things moving and like you said, make sure that we provide for enough lead time, because of all the hurdles you have to go through anymore, especially in this Marcellus and getting things done. But we feel very confident that we will get it done and get there.

Thank you.

(Operator instructions)

And our next question comes from Welles Fitzpatrick of Johnson Rice.

Good afternoon.

Good afternoon.

You hit on it a little bit, but as far as acquisitions in the Wash go, are you still thinking that 40,000 can be the ultimate target, or has that opportunity set maybe -- maybe shrunk up a little bit? How are you looking at that going forward?

Oh, I don't think that there's any magic about 40,000. Is it getting more competitive? Sure it is. You read about it all the time. Chesapeake says it's their best play. We say it's our best play. And you read about some of the other players. You know them better than me. But we're spending time and effort up there, and if we get to 60, we'll get to 60. And if we get to 80, we'll get to 80 if it makes sense. So nothing magic about 40, and I sure think we can get there.

Yes, one other thing to add Welles. We're leasing in plays other than Granite Wash. We are leasing in some -- that you'd typically reference as conventional plays. i.e. the fractured reservoirs, or piped in like the Cleveland Tonkaway. There's (inaudible) in play. The people are starting to talk about up in the Panhandle of Oklahoma. There are those kind of opportunities that are non-Granite Wash that we think have horizontal applications.

Yes, that's very appropriate. I'm using Granite Wash when I should probably be using the word "midcontinent," but Baird is right, as he said.

Okay. And in that Mountainview area, do you guys have an idea type of gas/oil ratio you going to be looking for there yet?

It will be about the same as what we think. It's early, but we think it will be about the same of what we see in the South Clinton wells.

Okay. And then in Sayre, in East Sayre, can you think about that stack, that pay column, and how you picked the zone that you're going to be taking it horizontal in?

Well, the plan is to drill a vertical pilot well first, and log it, understand it, and then take the best -- take the best shot after that lock sweet is run, and figure out a good time, which one we got to take horizontally. But the problem will be three or four -- at least three or four opportunities in that overall interval, the gross interval.

Okay. And assuming success in the Mountainview area, how many rigs do you think you would be able to ramp to in '11? Six, eight, is that too much?

That's probably too much. I'd say comfortably once we get two or three of these wells drilled, you could probably get to three to four in '11.

Okay. So it's three to four in Mountainview?

Yes. Just in Mountainview.

Okay. Sorry. I was talking -- that's perfect. Thanks, guys.

Thank you.

And our next question will come from Biju Perincheril with Jefferies & Company.

Good afternoon. In Granite Wash, the south -- the Mountainview prospect that you're drilling, first of all, can you talk about if there is any well control in that area, in the Granite Wash, and can you (inaudible) give us some color on geologically, how does that compare to the South Clinton area?

Yes, Biju. There is some vertical well control. In fact, every Granite Wash well prospect, that's the beauty of (inaudible). Typically there's plenty of vertical well control that helps you lessen the risk. There is -- there's a well. I can't remember exactly how far away it is from our well, but it's less than two miles. It's a very, very good show well, as we refer to it as. So that helps reduce risk. There are other wells, vertical wells, current in Mountainview that helps us determine one of these [fans] look like. We're going to watch fans look like. What was the second question?

Just -- just when you're looking at the geo as comparing it to South Clinton. From a geological standpoint, how do they compare and what quality, if you have that information?

You know, they are about the same, we think. Mountainview may be a little tighter based on what we know, but it's a lot of thicker.

What we lose in (inaudible) we gain in thickness. It's a good way to summarize it.

Okay. Thanks.

Thank you.

And it does appear there are no further questions in the queue. I will turn the conference back over to our speakers for any additional or closing comments.

Thank you, Shannon, and thank you to those of you who were on the call. As I say, we'll -- this is our first shot at it as a pure play E&P company, but we'll see you again next quarter. Thank you.

That does conclude today's teleconference. Thank you all for your participation.