Ranger Oil Corp (ROCC) 2007 Q1 法說會逐字稿

Welcome to the Penn Virginia Corporation first quarter 2007 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, President and Chief Executive Officer. Thank you, Mr. Dearlove, you may begin.

Thank you, Joe. Thank you. And good afternoon to everyone who is on the call. I'm joined here today in Radnor by Frank Pici who is our CFO, Baird Whitehead, who runs our oil and gas company, Nancy Snyder, who is our General Counsel, and Jim Dean who is our Investor Relations person.

In Kingsport, we have Forrest McNair, who is our Controller, and Keith Horton, who runs our coal company, and I believe, I think, in Houston, I believe we have Ron Page who runs our midstream oil and gas company for PMLP. So cast of thousands, and we'll do our best to tell you what's going on and answer any questions you may have. I'll follow along the release. I'll use it as a guide, but not necessarily read it to you. But with that in mind, let me get going.

The quarter for Penn Virginia Oil and Gas, the wholly owned sub of PVA, had a very solid quarter in terms of production, in fact it set a record for production for the quarter for the sixth consecutive time at about -- not about, it came in at 8.7 billion cubic feet equivalent, which was significantly over the first quarter of 2006 and slightly over the previous record, which was the fourth quarter of 2006. For March, it doesn't say, in this release, it may say it in the operations release, for the month of March, we averaged over 100 million a day the entire month. And for us that is the first time we've achieved that milestone.

Following again the release, for Penn Virginia, operating income in the first quarter was $38.5 million which was lower than the $48.7 million in the first quarter of 2006, it's actually somewhat higher than the fourth quarter, but lower than the first quarter. And that lower result was driven by a lower operating income from oil and gas company, which we'll talk about in a minute, some higher corporate expenses. And it was offset somewhat by higher operating income from the MLP PVR.

The main culprit, again, we'll touch on this in another minute, the main culprit in the oil and gas results was prices, which were down significantly from $8.92 per thousand cubic feet of gas in the first quarter of '07, to about $7 in the first quarter of -- excuse me first quarter of '06 versus first quarter of '07. Net income was -- just came in at $4.4 million versus 24 million the first quarter of '06. And this decreased in part because of the operating income, but mostly driven by a -- the non-cash effect of changes in the valuation of unrealized derivatives positions. And when we get to that, Frank Pici will talk a little bit about that. And I'll let that go until we get a little bit deeper into the release.

Let me just turn to the oil and gas segment for a minute here. As I just mentioned, operating income was a little bit lower in the first quarter of '07 than'06 despite our record production. The specific numbers are in the release at $22.6 million in '07, $33.7 million in '06. And as I also just said, prices were the culprit, down roughly 22% comparing those two quarters.

There is an explanation of expenses in the release. Operating expenses the only one I'll really dwell on for a second. They were $1.02 per [am] versus $0.69 in the first quarter of '06. To put that in some context, they were $0.93 in the fourth quarter of '06. What's going on here is a number of things. Oil fuel service costs are up to be sure. There's some one-time costs, although it's fair to say that there's one time costs in most quarters but the one time cost in this quarter were some surface and subsurface projects in the Gulf Coast and in the Cotton Valley.

There's some water disposal activity in Appalachia we had said we mentioned in our operating release that we had shut in some wells in Appalachia due to water disposal issues. But we're also producing from others that had water and so we had to move that water around. It cost about a buck a barrel to do that. That cost is behind us now. We have a disposal system in place. We'll be able to dispose of water from $0.10 a gallon and we'll turn on and bring online those wells that were off.

I guess the other thing that might contribute to LOE being up a little bit is the fact that we've been so successful in the Cotton Valley. And we're now establishing operations in the mid continent. And those tend to be more expensive places to do business than certainly the Gulf Coast of Louisiana or Mississippi. So you're just seeing, as the company shifts the nexus of its operations a little bit, you'll see some of these higher costs. I think our projections for the rest of the year in terms of LOE costs are probably between 80 and 90 cents an am.

We expect them to come down a little bit, but not probably return to where we were back in the early part of last year. The rest of the expenses that are highlighted in here, I think are fairly self-explanatory. And have before I get into the discussion of how the MLP did, let me divert over to the operations release which also went out yesterday with regards to oil and gas. As it says in that release, CapEx through the end of March, we had spent $99 million out of a projected $334 million, or roughly 30%. Most of it was spent on development drilling, roughly $70 million to drill 67 gross, 52 net wells with a 99% success.

Another $19 million was spent on exploration where we drilled 7 gross, 4 net -- excuse me, 3 net wells, 4 of the gross wells were successful, one was not, and 2 are under evaluation. The other $10 million was spent on the things you need to do if you're in this business. Facilities, leasehold, seismic, et cetera. That's where the CapEx went, or a significant bit of it went in the first quarter. Clearly we expect that perhaps to slow down a little bit given that we're at 334 and we spent 30% of it in the first quarter.

Just very briefly, because I don't want to read the operations report to you. I think it's fairly complete. But in the Cotton Valley, we drilled 23 gross wells, 16 net,18 of those 23 were in our AMI with GMX and 5 were within our 100% working interest area. All of them were successful. The significance of that is that I think that it gives us increased confidence of the viability of our 100% working interest acreage, which is close to our GMX AMI, but not, it's contiguous to it, but north of it. And it just gives us some more confidence, more confidence that things are working out there. We've got 5 rigs running right now. I don't think there's a plan to increase that many significant way.

I guess two things of note. First off, the Railroad Commission approved 20 acre spacings across the entire 38,000 net acres that we have. That won't make a big difference this year, because we're running about the same number because we're running about the same number, we expect to keep running 5 rigs. Over time that certainly will make a difference, or we expect it to. We'll begin to drill some wells on 20-acre spacings this year.

The other thing perhaps we hope that will turn out to be significant is a horizontal program. There's two legs on that stool, if you will. One is in the lower Taylor sands where we're hopeful the horizontal drilling will unlock that. And if it does, we think that sand is pretty pervasive across our acreage. The other is a horizontal test we intend to do in the Bossier Shale, really. Both of these tests, we had hoped would come off in the first half of the year, but looks as though they'll be in the second half. And that's simply because we don't want to get the rig in front of the signs. We're studying what we want to do and why we want to do it and taking some care to design a program that we hope will work.

In the Selma Chalk, 19 successful wells out of 19 attempts, 2 rigs running, may go to 3. Again, what's coming is horizontal test. We've completed 2 horizontal wells in the Chalk, both are successful. We're also under way doing some 10-acre, 5-well 10-acre spacing test is underway. The significance are as follows: The 10 acre spacings would increase the number of reserves, if in fact we prove that that works. The horizontal drilling will increase basically net present value. You're going to get a bigger bang for the drilling dollar if that in fact works. In the mid continent, as the release said, we've got 10 CBM wells that we drilled and I'm talking in gross numbers now is 9 total net. 2 granite wash and 2 horizontal Fayetteville Shale wells.

Got a couple rigs running in the CBM and one in the Granite Wash. To date all of those wells were commercial successes. In Appalachia, again, I think the big news there is the water system, which will allow 11 wells that have been shut-in to come online. You can't expect and shouldn't expect to see some bang out of that. There'll be some dewatering that goes on before those wells are fully engaged. Depending on where you are in the play. But we've got 4 rigs running, we've drilled 14 gross, 9 net wells, 13 have been successful. 12 out of 13 have been successful, but we're -- development wells we drilled, an exploratory well that did not work. What's new in Appalachia, is that 5 exploration wells that we've got on the docket, all of them in the Devonian Shale, we would expect to spud the first one of those this month, May.

Finally, and I'm done, finished with this, the Gulf Coast we drilled 4 gross wells, 1.2 net, 2 are successful of those 4, the other are under evaluation. To put the Gulf Coast in some context, it's very important to us of its production contribution, but it's only 7% of the budget. So it's an interesting situation for us. I think Brigham has released this and I know I read something from CapitalOne, about Cotton Land number 1 and Cotton Land number 3, which are not to be confused with the Cotton Valley. There are two wells in south Louisiana in a place called Bayou Postilion. I think we think there's some other locations there to drill, those two wells together making about 35 million a day. And we have the significant close to 40% revenue interest in them. If I said that right, and I think I did. So very significant to us. And I go through all of this.

I know you can read the release, but I'm trying to illustrate to you that the scope of what we're trying to do here and what we're becoming. We're surely not Exxon, but we're becoming a company positioned to grow on a number of important new areas. If you think about it, 62% of our budget this year, our CapEx budget is devoted to the Cotton Valley and the Mid Continent. And yet neither one of those things was either in the portfolio 3 years ago, and the Mid Continent only came online got involved there, I should say it that way I suppose, in 2006. The oil and gas company in my opinion, at least, is really kind of coming into its own in many respects.

Turning to the MLP side of the house, Penn Virginia GP Holdings, or trades under the symbol PVG, owns 42% of the limited partner, 100% of the general partner, and all of the IDRs in something called Penn Virginia Resource Partners, which we established about 5.5 years ago, 6 years ago, I guess. We own -- we meaning PVA, owns 82% of PVG. Everything PVG owns is PVR. There's a lot of PVs running around, but it's actually not that difficult to break it down. While PVG is down a little bit today, we launched it on December the 5th 2006, and since then it's traded up significantly. It's up over 45% in about 4 or 5 months. It's done very, very well for us.

We recently announced, its Board of Directors recently announced an increase in distributions of $0.24 per unit to $0.26, which is an 8.3% on an annualized basis. So I think PVG has certainly done extremely well. And as I've said PVG's cash flow is totally dependent on the success of the underlying MLP, PVR. PVR's distributable cash flow for the quarter was $26 million, up over the first quarter of 2006 by $2 million, and by $1 million over the fourth quarter of 2006. So it's off to a good start, as well.

The release touches on the two major segments of PVR, one is coal. Again I emphasize it's not an operating company in the sense, it's a royalty company. In other words, we own the coal, other people produce it. Production from those other people, those lessees, was 8.3 million tons in the quarter, which is up from the 7.7 in the first quarter of '06 and fairly flat with the fourth quarter of '06. Increases year over year were basically due to acquisitions. Royalty rates, which is how we get paid, were $3.02 a ton for the quarter, which is up from $2.90 in the first quarter of '06 and $2.99 in the fourth quarter of '06. So consequently you might expect, production's up and rates are up, revenues were up and operating income and cash flow were ahead of the corresponding numbers in '06.

On the midstream, natural gas side, now early in the third year of being in this business, just to remind you, we've got 4 separate gathering systems and 3 plants located in Oklahoma and Texas. The system throughput volume, as I'm reading now from the release, was 177 million a day in the first quarter, ahead of the 158 that we had in the first quarter of '06. A lot of that volume increase is due to a bolt-on acquisition that we made in the middle of 2006. If I was to compare the volumes for the fourth quarter of '06 with the first quarter of '07, you'd see they were down slightly, about 5% from 182 to 177. And that's due to some maintenance and some very cold weather that we experienced that caused freezeoffs and other difficulties in gathering gas.

Also then the other component of what goes on in the natural gas businesses. The processing volumes, or the margins I should say, the volumes and the margins are what matter. The gross midstream processing margin was $0.98 per thousand cubic feet in the first quarter of '07. And it was $0.74 in the first quarter of 2006. So a significant increase there.

And I would say that that's a fairly volatile number. It moves around. It's in -- to some degree, driven by the relationship of oil prices to gas prices rather than either of them in an absolute sense, at least in certain types of contracts. Nevertheless, the take away here is that both the coal and the midstream segment enjoyed positive first quarters that contributed then to PVR being able to raise its distributions, and in turn, PVG being able to raise its. And that's what the release is really telling you.

The next segment of the press release is capital resources and derivatives and that's followed by a discussion of our guidance. And for that, I'd like Frank Pici to walk you through that.

Thanks, Jim. Good afternoon, everybody. Wanted to give you a quick update on our capital resources.

Really our borrowings first. Our borrowings did increase over year-end, up about $53 million from year-end '06. That's really a function of our capital spending program this year. And we did say early on and have maintained that we'll outspend cash flow this year. And we did so in the first quarter. We're partially a little bit ahead of schedule on an annualized basis on our CapEx program, but not much. We'd expect to see some increasing borrowings as we go through the year, as well. We've got plenty of capacity in our borrowing base and credit facility to do that.

On the PVR side, borrowing was pretty flat from the end of the year till now, that reflects the reduction in debt as of year end '06 as a result of the PVG IPO and the proceeds from that that we used to repay debt down at the PVR level. Taking a look at derivatives, we did report a significant loss on derivatives in the first quarter. You probably noticed that in several other independent oil and gas companies, as well. It seems to be a fairly common occurrence this quarter as a result of the increasing futures. prices during the quarter as compared to year-end. And we reported a derivatives loss of $16.7 million.

The break down on that really was on the oil and gas side, our oil and gas base derivatives about $14.1 million. The rest of it about 2.6 from our midstream derivative positions. However, that's really just the change in the mark to market value and the change in the valuation. What had happened was we went through the second half of '06 as we had built up some pretty big gains really of s really as prices declined, strip prices declined through the end of the year as they recovered, of course, we gave those gains back in the first quarter. But as I said, they are non-cash.

In terms of cash settlements, and what really affects us from a cash flow standpoint, actually we had cash receipts on our derivative position during the first quarter of about $5.6 million in the oil and gas segment, and we paid cash out of about $2.1 million in our midstream segment. The effect of those things was to, when you look at it in terms of our realized prices in our natural gas revenues, we had a net pickup in our realized gas prices when you consider those payments we received on the hedges of about $0.62. So the realized price went from about $7 to $7.62 an MCF. On the oil, was pretty insignificant.

On the oil -- on the midstream side, the processing margin because of that $2.1 million of payments on the midstream side, took the midstream processing margin down on a realized basis from about $0.98 an MCF to about $0.90. So that's the real cash impact of what happened in the first quarter on the hedges. Looking -- looking forward, the oil and gas segment is about 45% hedged for the remaining portion of 2007 and that's based on current production rates. We use process collars primarily, there's an average floor there of about $7.50 and average ceiling there of about $11 for 2007. So they're pretty healthy collars. We go into -- as we go into 2008, of course those percentages drop down a bit to I think down and around the 25% range at present for 2008.

On the midstream side, we've recently, subsequent to March 31, we layered on a couple of other hedges that have taken the midstream's hedging percentage from low 30% range to about 60% hedge for the remainder of 2007. We remain about 30% hedged for 2008. And this is on net NGO volumes, by the way, in the midstream business. The new positions we laid on have locked in a nice processing margin for us on a significant portion of our remaining NGO volumes for 2007. It's allowed us to lock in some processing margins above budget. And allowed us to take advantage of some frac spread environment that is higher than normal. So that's why those positions were layered on.

With respect to guidance going into the remainder of 2007, if you look at the guidance table that's been provided in the release, there were a few changes there. On the -- and I'll just work my way down the page. In the oil and gas segment, the only significant change in production is we just narrowed the bottom of the range a little bit on production from the last release. On the expense side, we have bumped up the operating expense guidance from the last guidance table we provided. That's really a function of the higher first quarter LOE plus an additional estimate for some additional G&A related costs and expenses that we expect to incur for the year and we've bumped up those expenses accordingly. We've made a slight reduction in exploration expense based on our success in our exploratory drilling to date.

And our DD&A rate we've bumped up a bit, as well as a result of our changes in our production mix in terms of where the production's coming from and also some changes for latest drilling cost assumptions. In terms of our capital expenditures estimates for the year, we're staying with the, pretty much the same assumptions there. We've shifted a few of the categories around in the ranges, for example, exploratory drilling shifted a little bit. But in terms of total CapEx, we're pretty much in the same range as we were on the prior guidance.

Booking down into the coal and midstream segments, we did not change our production guidance in either one of those, nor did we change in the coal segment, the average royalty per ton realization. Those are as provided last quarter. Expenses on the oil and gas side, we once again also bumped up our depreciation estimate a bit just for the sort of mix in production. We've got a little more high cost basis coming out in the rest of the year as we expect it now. Looking at the midstream side, no major changes there. We did tweak the capital expenditures a bit to provide more a current estimate, but nothing major.

Down under corporate and other, we have increased our G&A estimate there, and once again, that once again is primarily related to a change in our incentive compensation. We've had some adjustments in prior years that came through the fourth quarter. We're just trying to spread those so that we can recognize and throughout the year. And really the other thing would be the change in the average long-term debt outstanding has tweaked up a bit, as well. I think those are the primary changes, Jim. And we'll of course take any questions during the Q&A session.

Thank you. Joe, I guess we're ready to take questions.

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

Thanks. Good afternoon.

Good afternoon, Scott.

In the Mid-Con region, nice organic growth sequentially there. Can you give us a little bit more detail? Was that a little bit ahead of schedule? Is that pretty much in line with your guys' plan?

Scott, it's a little bit ahead of schedule. We have drilled some very good CBM wells in the quarter. Some 800 to a million a day type CBM wells. And those kinds of wells can affect your production considerably in a short period of time. So we're a little bit ahead of schedule.

What was your expectation, sort of you said 800 to a million. What did you sort of have as a base expectation there?

Our typical tight curve for a Arkoma Coal well for is about half a million a day initial rate.

Okay. Well, I guess at the end of the day it's not necessarily you guys did more drilling, it has to do with just the results were better than expected?

That's correct

Okay. And then turning to the Devonian Shale well, I guess it's going to potentially start drilling in May. Can you kind of give us a time frame of how long that's going to take to have drilled and what the evaluation process on that is going to be?

That's not an easy answer. But we're drilling -- first of -- it ought to be straightforward because there's plenty of vertical wells drilled in the area. And from a planning standpoint and an operational standpoint, it ought to go fairly quickly. If I had to guess, we ought to be able to drill those wells in 2 to 3 weeks. The ones up in Mason County are similar, shale is about 3500 feet deep. We ought to be able to drill those in 2 or 3 weeks.

The unknown is when we're going to drill down in Wyoming County, which is on our mineral acreage. This is 6500 feet deep. And nothing's been attempted at these kind of depths in the Devonian Shale. At least not in that area. That's the big unknown. If I had to guess as far as results, we ought to have a pretty good sense for whether this stuff is going to make any sense for us at least from a productivity standpoint by the end of the year. From a cost standpoint as you would expect, our costs are going to be higher than some of the other costs you're seeing being advertised. We're going to do some science at least on the initial wells. We ought to know if it's going to make sense economically from a production standpoint.

Yes. I guess, kind of on that same thought. What would you -- what kind of rates would you need these wells to quote unquote make economic sense here?

Well, I think probably 800 to a million a day initial rate, maybe a little bit less than that.

Okay. Thank you.

Thank you, Scott.

The next question is from James Mooney with Carlson Capital. Please state your question.

Good afternoon, gentlemen.

Hi.

Your larger cap peers have recently announced their intention to form master limited partnerships with EMP assets. Can you give us your thought on the valuation discrepancy between some of the existing MLPs that have Appalachians EMP assets?

And who?

And your Appalachian assets.

Well, if you're talking about Lynn Energy specifically or maybe not. I think they trade on yield rather than anything else. I don't know any better answer than that. They're MLPs and they're not, many of them are LLCs. I think the world thinks they're MLPs and treats them accordingly. There's nothing wrong with them, but I think they trade on yield and we don't.

If you chose to do so, is there anything that would prohibit you from dropping down some longer life assets in the PVR?

Yes, there is. And it's just the manageability of the whole thing. That would give us 5 companies, one of the biggest criticisms that we get right now is we're too confusing. I don't think that would do anything to clear that up. And in fact, then you'd have two pieces of an oil and gas company that are liable to be valued differently. I think it would add to the confusion. I think we're not really big enough -- my opinion -- this is my opinion, and it's under review constantly, and we'll have a Board meeting next Tuesday, and I'll guarantee you there'll be some discussion about it, but that doesn't mean it'll result in anything.

The -- I don't think we're big enough to have enough of these so-called long-lived assets to drop into an MLP or an LLC. There's different opinions about that. But let's just look at Appalachia, there's almost no comparison in my opinion between us and Lynn.. Most of what we're trying to do and surely where the growth is coming is from horizontal CBM. The decline curves on one of those wells is more like you'd expect in the gulf coast. This is not quote unquote Appalachia production where you've got 50 years and you're making an MCF a day for till 3006. This has a fairly steep decline curve and maybe isn't a good fit. You could go through us asset by asset. You could argue, you could put Mississippi in there and you could argue you might be able to put some Cotton Valley in there, but even that's a pretty steep decline. I don't think we've got a lot of assets, frankly that fit into that structure.

Thank you very much.

the next question is from Richard Tullis with Capital One Southcoast. Please state your question.

Good afternoon, gentlemen, how you doing?

Good, how are you?

Doing fine. Couple of broad questions at first. What was your production at the end of March company wide?

103 a day, something like that.

103. Approximately where are you today in production?

We're between 105 and 110.

Okay. Turning to the Cotton Valley, give us an overview of your thoughts on your 100% acreage position. I think you drilled 5 wells there in the quarter. What are you seeing in those wells?

Richard, different parts of the Cotton Valley appear to be productive. Different parts of the Cotton Valley productive up in the 100% acreage than what they are down within the GMXMI. One thing we have found consistently that we're starting to do recently is to treat a lower part of the Taylor, which is the bottom part of the Cotton Valley that we determine through production testing that we were not getting stimulated even though it was perforated. So we have that on an additional frac stage on this lower stuff. And what we are finding that lower stuff appears to be acting the same across both areas, the GMX area and the 100% area.

The thing we're finding differently, the upper part of the Taylor acts differently in the 100% acreage than what it does in the GMX area. It appears to be more water productive up in the 100% acreage. But on the other hand, the Davis appears to be more productive because a higher reservoir quality up in the 100% acreage than it does in the GMX area. I probably have you totally confused.

No, no, that's fine.

It probably shakes out about the same reserve wise between both areas.

Okay. Do you have any of the five wells on yet?

We are laying a pipeline as we speak. Not only for the wells we drilled, some of the wells we drilled this past quarter, but wells we drilled last year. So we should have 5 or 6 wells, new wells on line up in that acreage within the next couple of months.

Okay. Can you talk at all about your -- the initial rates when you tested?

We have seen rates anywhere from 500 a day up to in excess of a million. You sort of get a statistical shakeout Some good, some bad, but all said and done, we end up with that 1 million to 1.1 million to 1 rate average. So far.

Well, thank you, I appreciate it, and keep up the good work.

Thank you.

The next question is from Jennifer Vann with BMO Capital Markets. Please state your question.

Yes, hey, this is [Ray Denham]. And Baird, I had another question about the gulf coast program. I was assuming you were going to drill a couple more wells around the cotton land for this year and then one more well. Does that sound about right?

We have drilled one well in South Creole the first quarter, which was successful. We plan on drilling one additional well in South Creole. And Brigham just spud the first of the two additional cotton wells, cotton land wells we're going to drill this year.

Okay. Got it. And your interest will be the same as it was in the first two wells?

The Cotton Land 4 our interest is the same as the Cotton Land 3. The Cotton Land 2, our interest is about 30-36% working interest.

Okay. Got it.

It's a little bit less.

Got it. And with the horizontal well in the Selma Chalk, what would you expect at this point even though it's early? What would you be looking for in terms of what that could do your rates of return?

Well, we haven't fully digested because we're waiting until we get some more production information to make that determination. At least based on what we know right now, these wells -- we're very encouraged. We're seeing the 3 to 3.5 times, which you would expect on the vertical well. So we're -- I'm positive as far as where this may take us. And we're going to get another horizontal well drilled before the end of the year.

Great. Okay. And just one last one. In east Texas, if you look at 20-acre spacing, we talked before about a $7 gas price, you thought kind of mid to upper 20s kind of rate of return. So if the down space well gets less reserves, it gets -- how robust does a 20-acre spaced well look? Do you think it'll just work in some areas? What do you think it could do to your probable reserves?

I don't think it's going to work across the board. We're going to try drilling 20 acre offsets to the best wells. We think that's going to be the best test because the best wells exhibit some drainage over a larger area, of course. If it works there, I would say that it's going to work widespread. If I -- this is strictly a swag because we really have not gone yet until we get some of these under our belt. I'd say it probably increased our probable and possible by 30 to 50%.

Okay. Thanks a lot.

Thank you.

The next question is from Monroe Helm with CM Energy Partners. Please state your question.

It has to do with the two horizontals you're going to drill in the Cotton Valley, the Taylor sand and the Bossier sand. Is this in your 100% acreage or is this in the GMX or joint venture AMI acreage?

This is in the GMX joint venture acreage on the 50% piece.

Okay. There's obviously been quite a bit of variability in some horizontals in east Texas in this Cotton Valley play. Is there anything that the -- wells have been pretty expensive and some of the production rates fell off pretty fast. Is there something you've come across that gives you some confidence that you're going to have some better results what some of the recent wells have been in this area?

Yes, because in that we refer to it as phase 2 area with GMX. Our best vertical wells have been in that area. In fact, we're averaging 1.4 to 1.5 down in that area. So we think the best chance it has for the horizontal well drilling would be in that area versus what you may have seen in east Texas. That's why we're doing it. If it doesn't work, we're probably going to abandon any further plans to do anymore of these things. The lower Bossier is something different that nobody really has attempted other than the one we did up in the phase I acreage that we had some problems on.

Okay. What kind of -- what kind of reserves do you think you need to make this Taylor interval work? and what do you think this completed well costs are for the first well?

I think we have for around 3.5 to $4 million if memory serves me correct. Reserve wise, around a 3BCF range, about 3 times.

Okay. Okay. Thanks for your answers.

You're welcome.

Thank you.

(OPERATOR INSTRUCTIONS). Your next question is from Scott Hanold with RBC Capital Markets.

Hey, guys. Just, I guess you mentioned that the currently production running at 105 to 110. It is somewhat surprising at such a strong rate. I guess a lot of that, correct me if I'm wrong has to do with those Bayou Postilion wells at this time?

That's correct, Scott.

And so, when you look at your production through the year, kind of seeing it sort of plateauing in the second and third quarter here?

No, I don't think so. I think considering we've got an active Cotton Valley program, we've done so well in the mid continent which we maintain an active program in. We continue to grow production in Mississippi, plus we have two more of these cotton wells to drill that will be on the -- they're not slam dunks because nothing south of Louisiana is a slam dunk, but they are lower risk just because we're offsetting some good wells. I think if you take into consideration all of that stuff, I would think we should be able to continue to grow throughout the year. There's going to be some variability month to month, of course.

Okay. And so then -- sort of on that same subject with those Cotton Land. If you look at your production guidance range is anything baked in that for any kind of success on those next couple of wells?

We have not -- we just haven't changed guidance because we're only a quarter into the year. I think if we continue to demonstrate strong results in the second quarter, I think you'll probably see a more material change in guidance.

Okay, fair enough. And one last thing. As we sort of move into, I guess, the summer season here, is there any capacity issues we need to think about as far as curtailments? Specifically in Appalachia?

No because we have firm transportation that handles almost all of our gas in Appalachia. Last year was probably a good test of the pipeline system, because storage levels were actually higher at the end of last year than what they are this year. So I think we'll be okay. There's been some new pipeline construction out of east Texas. We just have not seen any problems and don't expect any problems throughout the year, unless it'd be catastrophic or maintenance on a pipeline or something like that.

Okay. Thanks, again.

Thank you.

We have another question coming from Monroe Helm with CM Energy Partners. Please go ahead with your question.

Sure. Two other questions. Back on this horizontal. What kind of gas price do you think you need over a period of time to meet your hurdle rates of return for these higher costs horizontal wells? You're talking about the reserve rates being 3 times as high. But the costs are higher too, so wondering what kind of gas price you need?

We typically think we're going to need around a $6 gas price for vertical wells. On a horizontal wells, assuming it works, $4.50 to $5 gas price would probably work okay.

Okay. And I think in one of your most recent presentations you actually increased your 2P and 3P reserves, can you talk about what led to that? I think you may have also indicated what you think your reserve potential is on your exploration program. Can you talk about that for a minute?

Not sure which -- I'm not sure which -- Mid Continent --

Mid continent was the big kicker.

There was some moving things around between areas, but Mid Continent would have been the big addition. What was the second question? I'm sorry.

I think you also had some reserve estimates on risk reserve potential for your exploration program that looked fairly significant.

That included and they weren't risk numbers. I think we had approximately 300 BCF in there.

Right. So those were risk numbers. Is that more exposure to the exploration drill bit than what you've normally had?

I think on the slide it broke it down and there was some Fayetteville in there, and that may have been and Devonian Shale, and Devonian may have been the biggest of the three pieces.

It's primarily the unconventional resource plays is where the -- where most of those risk exploration reserves would be. Having said that, of course, some of the south Louisiana things we have on our plate we would have also risk reserve associated with those. Because of the risk, they'd also be small.

I guess my question is is that 300BCF risk potential, is that greater than what you normally have in your exploration program? Or is that kind of standard?

I think we have tried to expose ourself more to those kind of resource plays over time. So to answer your question, we have, we have grown that side of the equation over the last couple of 3 years.

Yes, I think by design.

Right. Okay, thank you.

Thank you.

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

Going back to the Cotton Valley. What's the cost been, average cost on your 100% wells there that you drilled in the quarter?

Down in the GMX area. It's right around $2.1 million. One thing we have seen -- the drilling costs have come down somewhat here recently on some of the rigs that are not under long-term contract. We're also drilling some of these Cotton Valley wells in extremely short periods of time. I think we have talked about it in the past 8 or 9 days. We just drilled one here the other day in just a little over 6 days. That's pretty remarkable, drilling a 10,000 foot well in 6 plus days.

Absolutely, yes.

We're trying to continue to drive our costs down. That side of the equation, we tend to keep driving our costs down with just by shortening our rotating time.

Okay. How many wells did you bring on in Cotton Valley in the first quarter?

I don't know the answer to that question, Richard.

Okay. Okay.

We tend to get those things in line fairly quickly after we drill them. The wells we carried over from the fourth quarter of last year plus the wells we drilled probably up through the February, probably got online. I can't tell you exactly what that would be.

Oh. That's fine. What's your current production in Cotton Valley?

Pushing 20 million a day net.

Okay. Very good, thanks, again.

Yes, you're welcome.

At this time, there are no further questions in queue. I would like to turn the call back over to management.

Thank you. Well, thank you very much for your interest and your questions. And we'll let you go and look forward to talking to you next quarter.

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