Battalion Oil Corporation (BATL) Q2 2008 Earnings Report, Transcript and Summary

Good morning. My name is Michael, and I will be your conference operator today. At this time, I would like to welcome everyone to the Petrohawk Energy Corp. Second Quarter 2008 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. [Operator Instructions] Thank you. I would now like to turn the call over to Miss Joan Dunlap.

Good morning. This conference call may contain forward-looking statements intended to be covered by the Safe Harbor Provisions of the Private Securities Litigation Act of 1995. For a detailed description of our disclaimer, see our press release issued yesterday and posted to our web site as well as our other public filings. I'll now turn the call over to Floyd Wilson.

Good morning, everyone. Thanks for joining. We find ourselves today in a particularly volatile time as far as the equity and commodity markets are concerned. We've seen times like these before and we'll see them again. It's our duty at Petrohawk, I believe, to look through these periods of extreme volatility and focus on the fundamentals of our business. After all most of our fields and wells will produce for decades. Petrohawk has been built on the premise that bringing clean, new homegrown energy is a long-term endeavor and that a serious focus on cost structure and margins will lead to shareholder value. It's our job to capture opportunities that lie within our influence and expertise and to provide a platform that can turn opportunities into values. We put the current uneven state of affairs for a side for a moment; we see that Petrohawk has positioned itself for many years of intelligent growth. In fact, we have claimed early mover advantages on an exciting new play, one that is developed in our own backyard, The Haynesville Shale. I'll turn the call over now to Mark Mize, our CFO for a financial review of the quarter.

Thank you, Floyd. I'm pleased to take a few minutes today to discuss the second quarter results of Petrohawk. This has been a very exciting quarter at the company, not only have we had strong operational results that will be discussed by Dick Stoneburner, but we also raised a fairly significant amount of capital for our company of about 1.5 billion net. We have had and continue to have a strong leasing effort in the Haynesville Shale, and add to a position that, already pretty significant for our company. For purposes of the operational results on this call today, I'm going to focus my comments on the highlights of the current quarter and stay away from any quarter '08 to '07 discussions, which lead to the transformation of our company in the first part of '08, and really transform our company more to a resource play company. We then generate oil and gas revenues this quarter of about 305 million, which is an increase over Q1 of just over 40%. We do continue to recognize very attractive price realizations with gas coming in right at $11 or 101% of NYMEX, which is just over the high-end of guidance, and oil coming in just under 118 a barrel and 95% of NYMEX, which is at the high-end of guidance. I'm starting to feel a little like a broken record, when we talk about LOE for Mcfe in Q1, we came in at $0.52 per Mcfe, which was a very attractive metric for our company. And in Q2, we came in just under that at $0.50 per Mcfe, which is at the low end of our full year 2008 guidance. All other operating cost metrics are either in line or under the low end of guidance except for gathering and G&A. Gathering and transportation as reported is slightly elevated over the high-end of guidance, primarily driven by slightly increased costs associated with our Fayetteville production. And looking at G&A for a moment, we're currently running at $0.55 per Mcfe as compared to $0.57 per Mcfe in Q1, and $0.71 in Q4 of last year. All of which excludes non-cash stock-based comp. My point discussing three most recent consecutive quarters is to demonstrate the declining trend. Looking at the current quarter, inclusive of non-cash stock-based comp, we came in $0.67 per Mcfe, which does exceed the high end of our full 2008 guidance by approximately $0.12. The elevated metric is in line with our first half of the year expectations, due to the impact of the sell of the Gulf Coast, where we sold about a third of our production and shed about 22 to 25% of our G&A costs. As we continue to ramp up in '08, we expect this metric will fall in line with the previously published guidance. A final item that I will address before speaking briefly about income taxes, is the write-off of about $3.4 million of MLP formation costs. Those were costs incurred and paid in 2007. We wrote them off in the second quarter of this year, as we had previously announced when we pulled the S-1 registration statement from the SEC. We have included these costs in interest expense and other, and we've also included them in our selected items table in our press release. We continue to recognize and an effective rate… effective income tax rate, substantially in line with guidance. And we expect AMT cash taxes this year, of about $26 million. 22 of the 26, has already been paid as we sit here today. All this being said, our reported loss, which is really driven by the unrealized non-cash derivative mark-to-market slips the net income of $15 million or $50 million or $0.23per diluted share, which is under the consensus by about $0.03. And then briefly touching on the balance sheet more specifically cash and debt levels, we ended the quarter with just under $500 million of cash and nothing drawn on our revolving credit facility, and that equates to a net debt to cap of about 30%. All this being said, I'll turn the call over to Dick.

Thanks, Mark and good morning to everyone. I'd like to spend a few minutes reviewing our second quarter operation that are not related to the Haynesville Shale play, before turning the call over to Floyd to elaborate on all of the extremely positive aspects of that play, hat have transpired, since we last reported to you. Petrohawk drilled a total of 198 gross wells in the second quarter, 93 of those were operated with an average working interest of approximately 58% and 105 were non-operated with an average working interest of approximately 10%. Six of those wells were unsuccessful resulting in a success rate of 97%. In the Fayetteville Shale trend, we drilled a total of 89 wells which was up 44% from the first quarter. 30 of the wells were operated and 59 were non-operated. Production volumes in the field continue to show strong quarter-over-quarter growth. On April 1, at the outset of the second quarter, our gross operating production was 74 million cubic feet per day. Three months later, our gross operating production had grown to 94 million per day or 27% quarter-over-quarter growth. Not only is our operating production shown strong steady growth, the non operating component is also growing very rapidly as evidenced by the non-op well count increasing from 36 in the first quarter to 59 in the second quarter or a 64% increase. As expected from this type of increase, our net non-operating production has increased quarter over quarter from approximately 9 million per day to 15 million per day or a 67% increase. The operating results from the Fayetteville continue to increase as well. Of the 30 operating wells drilled in the second quarter, we have performed state tests on 17 of those wells. Eight of these wells were located in the northern region of the trend in townships 11 and 12 north. The average test rate from these wells was 2.3 million cubic feet per day, which compares to the average rate of 1.7 million cubic feet per day from wells tested in the fist quarter in the same region. There are also several excellent wells in the northern region than had recently been put on production, but have not yet had a state test performed. The most notable is the Brown 11-13 number 516h, which had an initial production rate of 3.2 million cubic feet per day from a cemented liner in a 2165 foot lateral that had a six stage frac treatment. This is the first cemented liner that we have completed in the northern region of the play. We will continue to evaluate the merits of this completion technique in conjunction with longer laterals, as we continue to actively develop this area of field during the second half of 2008. We are also active in other areas of the field during the quarter. We completed and had four tests, four wells tested in the southwestern portion of the field with an average state test of 1.7 million per day; three wells in the central portion of the field with 2.7 million per day and two wells in the southeastern portion of the field with an average state test of 1.6 million per day. We recently brought on production in another well in the southeastern portion of the field the Sequoia 9-12 number 1-19h, at a rate of 2.7 million per day from a cemented liner with the lateral length of 2984 feet. This is the first cemented liner completion we've had in this area of the field and much like the results of the Brown 5-16 in the northern region, we will continue to drill longer laterals and employ more cemented liner completions in order to attempt to optimize our completions in the field. Additionally, we were well underway with the construction of multiple gathering lines throughout the field. Once these lines are completed which is expected to be prior to the end of 2008, we will be able to deliver our gas from all of our operated areas of the field directly to the boardwalk system, further enhancing our realized pricing and also providing more direct control on the volumes that will be delivered. Our conventional Allen Grove drilling operations continue to deliver excellent results by means of vertical drilling, horizontal drilling and re-completions. We drilled a total of 40 wells during the quarter of which 30 were operated. Of the 30, 27 were vertical wells and three were Lower Cotton Valley Taylor Sand horizontal wells. The Lower Cotton Valley Taylor wells continue to provide excellent production volumes as evidenced by the average initial production of these three wells being 9.5 million cubic feet per day. In addition to the drilling operations, we had excellent results re-completing wells in the Hosston. A good example of this was the activity conducted during the month of May during which we re-completed 13 wells. The incremental production of gain from these 13 operations was 11 million cubic feet per day gross and 7.5 million cubic feet per day net. We also experienced excellent results from the drilling program in the Terryville field. Our focus in this field has been twofold. One; we have continued to accelerate the development of that portion of the field that has an expanded Bossier section of the 16 operated wells that were drilled in the field during the quarter, 11 were completed in the Bossier and Lower Cotton Valley sands with an average initial production of 5.6 million cubic feet per day. The other primary focus has been the ongoing effort to acquire three seismic over the Terryville extension. We anticipate beginning the acquisition phase this month and should have processed data delivered earlier in the fourth quarter. A number of other areas in the western region of the company are also very active. We drilled our second horizontal well in the WEHLU field and expect to have it completed by mid August. We're also adding our second and third operated rigs in this field this quarter and look forward to some significant contributions in the fourth quarter. We have drilled 17 wells of the 24 well program in the Sawyer field in Sutton County with excellent results in line with our expectations. We also will be closing our area of mutual interest with EOG Resources today and expect up to seven wells to be drilled in this area before the end of the year. Lastly, we have increased our non-land component of the capital budget from $950 million to $1.1 billion. The break out of this budget by region is as follows; Haynesville Shale will have $218 million, Fayetteville Shale, $395, Conventional Elm Grove $208 million, Terryville $86 million and the western region $193 million. With that, I will turn the call over to Floyd.

Thanks, Dick. At the forefront of the information we bring you today is our Haynesville Shale update. We've continued to increase our base in the shale in northwest Louisiana and East Texas. Our research and success indicate this to be a breathtaking opportunity in this awesome play. We have discovered rock saturated with natural gas and with characteristics that make Petrohawk's' techniques for extraction work extremely well. Our first two wells have had initial production of nearly 17 million cubic feet per day each, higher evidently than some 2,000 shale wells I heard mentioned last week. During 2008, we are planning to drill about 30 Haynesville horizontal wells and have a clear path to assembling a sizable rig fleet; 10 horizontal rigs by the end of this year and 20 during 2009. We have secured the rigs for this program, and we intend to execute this multiyear development program. Our development plan calls for about 140 operated wells in 2009 and more wells in subsequent years. Our drilling program is positioned to drill at least one horizontal well per section in those sections that involve three-year lease terms. Should point out though, that only about half of our 300,000 net acres in the Haynesville area was leased on three-year terms, so our overall development horizon is greatly extended. History tells us we will figure out how to drill more, better and faster in this new play as we advance down the learning curve. In the Haynesville, we not only have pricing advantages based on the location of the play in comparison with other major US natural gas plays, but Petrohawk specifically as advantages in infrastructure and local knowledge. Having had agreements in place as an example for transporting gas to preferred markets for quite sometime. We're continuing to build on those agreements to ensure long-term capacity. Just as capital within a company is typically allocated to the best opportunities, companies migrate towards the best opportunities and we have seen many new entrants in the Haynesville Shale recent weeks and months. The shale works economically in a wide variety of pricing environments and of course companies are looking for places they can operate at low cost and realize high relative prices. And for us, based on all of those reasons, the Haynesville is the ultimate long-term opportunity. We have approximately 300,000 net acres leased or committed at this stage at an average cost about $5,000 per acre. Our leasing activities in the shale are disciplined keeping to what we believe to be the core of the play. We've completed our second well in the Haynesville for a rate of 16.7 million per day. You may remember that our fist well was completed at the rate of 16.8 million per day. Wells such as these pay out quickly and support an efficient recycling of cash and we'll put this cash to work growing this play. And we have drilled several other wells so far, not having been completed yet, each having the requisite thickness and quality that should lead to above average production. We expect our borrowing base in our revolving credit facility to increase from 800 million to 1.1 billion. Our philosophy on hedging remains unchanged. We're about 70% hedged in 2008 on expected production and we'll build our position in future years to about that same level. Our approach to growth is balanced and for a company of our size to become a significant established operator in a play of this magnitude, speaks to our ability to move quickly and maintain adequate liquidity to accomplish our goals. These goals include average year-over-year production growth of 25% for 2008, even though we expect that the real full-year impact of our Haynesville production won't get until 2009. We expect our fourth quarter 2008 production to be 50% higher than it was in fourth quarter 2007 and that 2009 will deliver between 30% and 40% organic growth over 2008. We'll spend a bit more than $700 million during the second half of 2008 for drilling completion and seismic and facilities and aggressive capital program that is well underway as we speak. Additionally, we are estimating considerable reserve growth this year and in years to come capturing our estimated 14 Tcfe of resource potential through drilling. Mid-year 2008 crude reserves are internally estimated at 1.3 Tcfe which is 25% higher than our approved reserves were just six months ago. This crude reserve estimate does not include any reserves from the Haynesville Shale, highlighting the fact that other areas of our company are following fantastic growth tracks in their own right. And we have received some great data in the Haynesville corroborating our reserve estimates on a go forward basis from independent core analysis of EGP number 63. We've included a lot of detail in our release today regarding the company's near and longer term plans, which I hope you all take sometime to look over. We cannot be more enthusiastic about where we are today. I would like to say that if you don't have some Haynesville, you should get some. Now, we have time for a few questions. Question and Answer

[Operator Instructions]. Our first question comes from Subash Chandra from Jefferies. Subash Chandra - Jefferies & Co.: Hey, good morning, Floyd. A quick question for you first on… I'm sorry on the Fayetteville. Is it safe to use sort of a 50% NRI on those gross volumes?

Roughly it's a little higher than 50 but that's pretty good for planning surprises, Subash. Subash Chandra - Jefferies & Co.: Okay, perfect. And then shifting to the Haynesville real quick. What is your internal estimate on regional take away capacity both on the trunk line and gathering level?

There's several new projects underway, which we're becoming involved in that are adding significant take away capacities from the region. Currently, we have provided ourselves enough capacity to take care of our needs this year and we're working with these providers in future years for future year take away capacity. It sounds to me like there's about two or three Bs per day on the drawing board for new take away capacity basically coming from lines that have looping going on and compression and what not. And these are staged in between mainly 2009 and '10, I think, maybe one of them stretches into 2011. Subash Chandra - Jefferies & Co.: Do you think some of those facilities I guess they kind of roll through a variety of shale plays? Do you see it sort of making these shale plays more competitive with each other really driving the lowest cost volumes into the pipeline?

No, that's the… I don't know that it really works that way. It's probably a little over my head but it seems to me that the fields that are the most approximate to the burner tip are the ones that will get the best service and of course this is one of the most farthest Eastern plays that's on a significant pipeline grid in the United States. Subash Chandra - Jefferies & Co.: Okay. And one more and I'll let others ask. In the 36 rig count sort of suggest that it's business as usual in your other plays. Doesn't make any sense at some point to sort of cannibalize activity elsewhere for Haynesville development or do you think you can sort of add Haynesville development to everything else?

As Dick pointed out in… as our mid-year reserve estimates points out, the other fields are delivering very exceptional returns on investment and growth activities. At some point in time, sure, you might migrate capital from those fields, but at this time, we feel like we can make the Haynesville program totally incremental to what we currently have on hand as we totally figure out the play and add rigs and what not, we'll certainly be considering that as an option in future years we don't intend that that be the case in 2008. Early on, I think, Dick and his staff took a couple of rigs from conventional Cotton Valley work and put them over into Haynesville, just to jump start the program. Since we've… I think since then we've replaced those rigs. As it gets more mature, yes, these projects have to vie for capital and the best use of capital usually gets the lion share. So I would expect that our 2009 budget would have a significantly different shape than our revised 2008 budget.

Your next question comes from Michael Hall with Stifel Nicolaus.

Thanks. As it relates to the rigs while we're on that topic, you talked about having rigs secured for your plans in 2009. Are those new-build rigs that you're funding the building of or is that just active leasing in the market?

There's about seven or eight new-build rigs that are staging in throughout the latter part of '08 throughout probably to the third quarter of '09. So we are definitely incorporating some new-builds into that overall rig fleet.

Okay. And then looking at the East Texas versus kind of Northwest Louisiana, at what point do you talk about having from East Texas, Haynesville/Bossier shale exposure? At what point do you plan to move east and test that or move west and test that?

We actually have some wells scheduled, a number of wells scheduled in east Texas from the northern end of the play in Harrison County down into the Shelby County part of the play for '08. So, if I understood the question properly, we are on the verge of initiating our Haynesville activity in East Texas

Okay. So you think you will maybe have some results regarding that by year end?

I would think so.

Okay. That's it for me. Thanks.

Your next question comes from Andrew Coleman with UBS.

Good morning, guys. I have a couple questions here on… what resulted in going to nine stages down from I think it was 12 between your two Haynesville wells?

I'll let Dick add to this but the first well, I think we planned for 12 initially and ended up with 11 stages. The second one we planned for nine and did nine stages has to do with the length of the lateral and our belief that shorter stages in terms of your frac job are preferable .:

Yes that's exactly right. It was just a little bit shorter lateral then the EGP. I'll add that we've seen some micro-seismic evidence from EGP that really is very supportive of our concept of shorter lateral stages or shorter frac stages as a much more effective way of treating the rock. So, we feel like we've got a good a pretty recipe.

Okay. What was the cost for that well? Did you say that earlier?

I don't think we said but I believe it's in the $8.5 million range. It was a well with lots of science and quite a few extra days drilling the pilot hole and what not. We're certainly projecting to get that well cost down significantly on an average basis over time. But these first few wells are quite extensive.

Okay, alright, great. And then looking at the reserves which were up you said 25% here for the first half of the year. Do you have a feel for how much of that was pricing related versus kind of performance I'm guessing probably two theirs to one third?

We're looking at that while we speak. I think most of it was through ads, but we'll come to that number. I don't really have a… where were prices at the end of the year?

Okay.

Listen. About half.

Half, okay.

No, no. Specifically it's 14% pricing and the rest from ads, contracting year end with mid-year.

Okay. And that report was run into June or was it run pretty recently?

It was run as of June 30 using SEC guidelines, but in the internal report.

Okay. Now then the 170 Bcf per section compares pretty favorably to what other competitors have put out there. I guess what do you think it would take to, I guess, increase the recovery factor which I think is somewhere around 30% to get something higher than 50 Bcf per section?

Well, first off, let me point out that we don't pretend to say that that recovery factor stretches across an area that's 4,000 square miles or more. We definitely feel like it gives good information for the section we drilled the well in and we intend to do a lot of coring in the early stages of this play so that we can get a lot of data in. We've joined some groups in fairly short order you're going to be sharing core data, so the industry as a whole has a lot more firm information to work from and perhaps get the well costs down. But the traditional thing would be more density in drilling and more effective frac jobs. That's what would get the recovery up. And as we've seen in other plays the efficiencies in recovery have really been growing over the last few years with somewhat higher gas prices supporting more wells and way better frac technology than we've had five years ago .:

Andrew, I'd just add I think it's just so early in the play, I think we're taking what we've been taking all along as a conservative look at what these wells will recover on a per well basis, on our percentage basis. We are undertaking a very, very extensive reservoir modeling study much like we did in the Fayetteville that will help us get that answer. But it's just real early and so it's just a conservative approach, I think, to use the type of recoveries that we're using.

Okay. And then the last question I had was looking at LOE with a $0.50 per Mcf kind of a run rate there and now Haynesville gas is much drier, but and higher pressure. Do you think you will have or can you break out what the LOE for that region might look like?

No, I'll see if Mark has a comment to add to this, but that particular region is among the lowest in all of our regions in fields in terms of the specific LOE running at $0.30, $0.25, even somewhat lower in some of the specific fields in the region. So it's a… we're expecting this to be a great add to the overall cost structure of the company. I'll point out that strangely enough we're seeing a little bit of oil coming out of the Haynesville which we weren't expecting. It's not a lot. But that may add to the equation as well. Anything, Mark, to add?

I have nothing to add.

Okay.

Thanks, Floyd. Appreciate it.

Your next question comes from Jeff Robertson with Lehman Brothers.

Thanks. Dick, as a little bit of a follow-up to the prior question. Can you talk about the continuity of the reservoir and the rock properties based on the wells you have drilled in three different parishes? And then secondly, as you all lay out the drilling schedule through 2009, how much of your 300,000 acre position currently do you think you will have tested?

But to the first question, I think the continuity of this reservoir is remarkable. We kind of knew that even before we got the core data back just using petrophysical analysis, visual petrophysical, analysis, from the log data. But the core data that we see supports everything that we thought that the vertical, Homogeneity of the rock within the section is very consistent so not only do you have a vertical continuity but you have a very, very strong lateral continuity throughout the entire area of the play. So, I think that speaks very to the consistent results you've seen so far.

Do you think there's any structural component to the play?

Minimal. There's not a lot of faulting in the area. There's some large regional faults, but their easily identified and we pretty much have a good handle on, what faulting exists. And other than that, I don't see any geo-hazards that get in the way of very extensive development of the area that's defined by the sub surface data.

Then on the drilling plans and how much of your acreage position you think you all will have tested and at least, as you start to refine the play going through 2009?

Well, I'd start the answer and let Floyd finish it. But he mentioned that we have approximately half of our acreage that either has longer than a three-year term or it's HPP [ph]. We feel like, with the rig program that we have and we're really working on some incredible efficiency ideas in terms of getting the well count per year with the 20 rig program up. But even at current expectations, we can drill well over 400 wells in the three year period that we have in front of us to hold about half of this acreage. So, I don't know if that really addresses your question, but we're going to have a good… well we're going to have all of this held by the end of the three year term, I feel confident. Floyd?

Jeff, if you move away from the idea that we feel very comfortable we can protect or hold all of our acreage and just get into the idea of defining, where the productive areas of this trend are going to be. We are testifying each single large block of leases that we own through the course of this year and next. We're drilling wells in and around Elm Grove and Longwood, and we have wells in East Texas. So, we're going to checkout every single area, where we have significant acreage holdings with our drilling program over this year and next. So, I think we'll have, if you add to that what our peers in this play will have found by that time, we're going to have really good definition of the productivity and where the limits of this trend are through the course of that time. In terms of continuity, I'd point out that our first two completions are 10 miles apart. And they were remarkably similar in our findings and productive rates, etcetera.

Thanks, that's the color I was looking for Floyd. And so, just lastly, on… in terms of leasing and continuing to expand the acreage, what kind of pace do you think you can be on given all the competition out there currently?

Well, Jeff, we found that we're as competitive as anybody with the one acreage. So, I'm preferring to think of our pace and our goal in acreage as being very quality control oriented. We're only looking for additional lands that add to existing pieces of the puzzle or that are smack right in the middle of our defined areas of significant interest. We're not out leasing land just to add numbers to the board. We're very selective in it, and so, our pace has clearly slowed down a bit, since the first six or eight months of activity. It's still a pretty good fast pace but it's much diminished from what it was. We're finding that already, we have room for several thousand locations, and even with some risk being thrown into that it's still into 2,000 locations, close to three maybe. So, we've got a formidable task ahead of us, just to develop all of that. So again, I'd just say our goals have to do with quality and core positions within our area rather than you know, certain number of acres.

Thank you, Floyd.

Your next question comes from David Heikkinen with Tudor, Pickering Holt. David Heikkinen - Tudor Pickering Holt & Co.: Good morning. With a $1.1 billion credit facility, you guys are in a position to finance your development with that data but the current plan and are you comfortable just running your debt towards those levels as you go through 2009?

Well, David, we always try to keep a buffer in the credit line for either opportunities or unforeseen things like dips in gas prices or whatever that may come up. But at this time, we're fairly well fixed for what we see in front us and what we see as our appetite for additional land and drilling so, Mark, anything to add to that?

No. As Floyd had mentioned earlier, we are in the process of undergoing the re-determination. We do expect 1.1 and there will be a buffer in the revolving credit facility just to give us the flexibility that we need to execute the program that's been laid out. David Heikkinen - Tudor Pickering Holt & Co.: Okay. As you think about going to the operations side, the cemented liners in the Fayetteville look pretty encouraging. Can you talk about what those wells cost and what they could recover? And then, are you making the shift to drill most of your walls with cemented liners now or is it still to early to make that shift?

I think it's too early to make the comment, as a definitive comment, but we always look at what we're doing, what our peers are doing and what's going to make the best well and well, we've seen some very positive results from the cemented liners. Southwestern has done a really good job, I think of figuring out the best way they think to complete these wells. I think they're on to some pretty good ideas and we're looking into what we're doing, they're doing, and we're going to continue to experiment. I hate to use the term experiment, we are just going to try to different techniques. I think sometimes spending more money is better, and I think Southwestern proved that to some degree, drilling longer laterals and fracking with more stages. So that's one of the emphasis… we will have an emphasis on that during the second half both in the shallow region and deeper regions to try more cemented liners, more stages, try and optimize results. So we're not abandoning the open hole system or the packer system. There will be certain areas that that will work the best but we're not keeping blinders on so to speak in staying with that system exclusively.

David, remember that for the quarter we're actually involved in a greater number of non-op wells than operating wells, and this provides us and our other partners a tremendous amount of data and knowledge and a chance to see how these things work out. So we are very interested and appreciative of the efforts of the other and certainly larger players in that area in terms of our R&D. David Heikkinen - Tudor Pickering Holt & Co.: Very good. And your current gathering capacity for the system you're installing?

You're talking about the system in the Fayetteville? David Heikkinen - Tudor Pickering Holt & Co.: In the Fayetteville? First.

Art [ph] is sitting in here… correct me, Art [ph]. But I think we're laying well over 100 miles of pipe and we intend to have or whoever has the data about 100 million throughput on our gatherings.

Right, with the expansion to almost double (inaudible). David Heikkinen - Tudor Pickering Holt & Co.: Sorry, I couldn't hear the answer to that.

We have about 100,000 capacity on the system we're building which could be expanded with compression to almost double that.

The 100 million.

Yeah David Heikkinen - Tudor Pickering Holt & Co.: Okay and then thinking about gathering in the Haynesville talked about 30 million of investment in this year, how much capacity does that garner?

That's an early stage estimate. We have a fairly significant infrastructure in place there already. We're actually buying right of ways and constructing multiple gathering, mini gathering systems around the outside edges of Elm Grove as we speak. There's 8 or 10 of those under planning or construction right now. We think we have it scoped out quite well to provide in field gathering for everything that we have on the drawing boards for this year and next, in terms of getting it out of the field and into the pipelines. Then of course Steve and Art [ph] and their group are working on the other end of that equation. And that's with the take away capacity on the… the large intrastate lines and perhaps even an intrastate line or two. David Heikkinen - Tudor Pickering Holt & Co.: In your goals how far are you planning on trying to get firm transportation? What… How far to the east do you need to go or to the south?

Let me just say that we view this firm transportation business as having been a very effective proven way to achieve better than average prices. We also look at this as insurance. So I'm going to let Art [ph] speak to the markets but we view it somewhat as insurance in that we will buy more firm space, a bit more than we know we're going to need just to prepare for some of these bigger wells or just to not be… not have a bottleneck. Art [ph], what about the markets?

Right now, I mean, everything is obviously moving east. The large part of our delivery's going to be at Perryville, which is in Louisiana, but we're also going to be delivering to Lebanon, Ohio and down into Mississippi at Kazi [ph] and we're also looking at some other things past Kazi [ph]. The Florida market's extremely hot. Everything in the southeast is growing. Northeast is where it's getting burned. That's where we're moving to. David Heikkinen - Tudor Pickering Holt & Co.: That's very helpful. And just one additional comment and a question as you think about focusing your assets, you've done a lot of that in the last year. Are there any other assets that you think you could monetize or as you focus in on the Haynesville and you talked about your capital deployment ramping considerably in '08 and changing from '08 to '09?

Yes, David. If Steve has something to add I'll ask him to join in here, but we've already basically scoured all of our regions and sold off most of the non strategic property so that what we have left in the western region is all very good property. Having said that, we certainly are currently considering the divestiture of certain of those fields and assets to take that cash and recycle it into the, really high growth programs that we're involved in over in Arkansas, and Louisiana and Texas. So we definitely have some ambitions along those lines. Steve, anything?

Yes. We're certainly looking at that, and it's a fairly active analysis we're going through right now if that helps to answer the question. David Heikkinen - Tudor Pickering Holt & Co.: It does. Thanks for answering all of the questions.

Your next question comes from Eric Hagen with Merrill Lynch.

Hi, good morning. First question, in terms of the rigs that you secured for the Haynesville. What are you seeing in terms of cost pressures?

Well, the kind of rigs that we're using are certainly in shorter demand than they were six or 12 months ago. So the cost… the pressure is definitely upward in those sorts of rigs. We probably could have hired that kind of a rig for less than $20,000 a day, six or eight months ago. And they're clearly up in the $25,000 to $30,000 a day, today. However, these are larger rigs as well so it's not… we're getting larger rigs in the play, bigger pumps, more capacity, a little faster penetration rates. All in all, we hope that the efficiencies won't be that much affected by the higher day rates. However, in particular this Haynesville play offers such a tremendous opportunity for present value if you can accelerate these things. So, ourselves and others are securing these rigs as fast as we can. We're fortunate that we have quite a spite of influence in that small area and we've been able to secure and we actually have all of these rigs secured for the next couple years in terms of growing the fleet from the current level of five or six rigs by the end of this month to 20 rigs during 2009. But, the pressure is definitely up on those, even in the context of gas prices being seasonally a little bit weak today.

I would just add that about half of those rigs that we had commitments on for the Haynesville program are either Nabors PACE rigs or H&P flex rigs. So, we're getting the best of the best. We're going to have a fleet that will allow us to perform our drilling operations without a question. And I think there is some comfort in having the quality of rigs that we're going to have, not just the quantity

Great, thanks.

Yes, I think that there's a move afoot to really look hard into pad drilling in this area. So, some of these rigs have stompers, I think so you can kind of move the rig just a few feet and spud your next well. So we're looking for rigs that are really fit for the job as opposed to just large numbers of rigs.

Great. That's was actually my next question in terms of spud to TD. Any early estimates to what kind of cycle time that might be?

Right now with the wells that we're drilling what we're gathering as much size as possible. And we're doing that on almost all of these wells in 2008. I'm sure there might be a few of these wells we have scheduled that we won't be drilling pilot holes on. But the ones we do will either be taking full cores or side wall cores and that basically adds about two weeks to spud to TD and that's about 60 days today. For our budgeting purposes and forecast purposes beyond 2008, we're assuming 45 days spud to TD. So we really think those efficiencies will grow. Time will just tell but like I said, we've got a smart bunch of engineers in Tulsa that they are working the problem and have a lot of outside the box ideas to even increase that efficiency. So we're looking forward to how we can accomplish that.

Thank you.

And Eric, we're thinking of about 15 days or so from TD to connection this year and next.

Okay. Great. The last question I had was on the land budget… I'm sorry, total CapEx this year? Any way you can give an idea of this at that stage? Not just the E&D, but everything in?

No. We really don't project that and as I said, we've been very active in the first part of this year and we expect to remain active. But kind of quality oriented in the second part. So we don't really have an answer for that. It's a highly competitive situation still and we don't like to highlight our plans.

Still kind of a moving target then on that? Okay. Great. Thanks, Floyd.

Your next question comes from Ron Mills with Johnson Rice. Ron Mills - Johnson Rice & Company LLC: Good morning. Dick, just a question on… can you explain a little bit about what you're doing with the pilot hole program? What the incremental cost is on the pilot wells and really at what point do you think you'll gather enough data from drilling the hole all the way through the Haynesville before you go horizontal? Before you just start turning laterally versus drilling the pilot?

The cost delta is around 1 million. So, our… we're looking at that $8.5 million range coming down probably around 7.5 and hopefully with more efficiency coming down even more. The pilot hole program is really going to be a fluid one. Like Floyd mentioned, we're going to be drilling at all corners of this play from the southern part of the Texas trend to Harrison County and all points in between. So, wherever we feel like the need for core data, we'll take it and log data as well. I don't know if that fully addresses the question, Floyd?

Keep in mind Ron, that if you have… if you're thinking of 80 acres per well on a section, you're certainly not going have to drill pilot holes in very many additional wells in a section or maybe none. And then to the extent the competitors have drilled pilot holes and taken cores and we're able to arrange for sharing of that data. In time, we expect that to become something that we do just to fill in the gaps rather than something we're doing because we're drilling these wells ten and 20 apart today.

Yes, I maybe just add. Floyd brought up a good point, the EGP and Hutchinson and the Hunt Plywood, which are our first three wells, all about 10 miles apart kind of spaced throughout the undrilled area. I don't think there will be a need for pilot holes between those wells. So, maybe that's a better addresses the question as we start having a pretty decent set of subsurface data within an area such as that and I think such as that and all of these wells in between we'll probably be able to eliminate the need for one. Ron Mills - Johnson Rice & Company LLC: Okay. And Dick, can you also address another operator yesterday mentioned there may be multiple benches within the Haynesville. I think you maybe even talked about that in the past as well in terms of as you move throughout the play, you may have different sources of contribution to the gas in place. Any comments about what the development looks like in the instance that there is... that there are multiple benches on the same section?

I don't concur with the concept of multiple benches within the Haynesville as we map it. This plus or minus 200 foot section that we reference and that our competitors' reference is a very consistent vertically consistent set of rocks. So I don't ... I think if somebody made that comment, they're probably referring to the Bossier section which is basically that entire section from the base Cotton Valley Sand down to the top of Haynesville. Yes, within that section depending upon where you under the field, there are a number of different porosity members that appear perspective and we're still doing a lot of homework on the Bossier. We're talking a lot of sidewalk cores in the wells that we're drilling and continue to gather data on the Bossier. But as a Haynesville comment I wouldn't concur with that.

We've seen some shows.

Yes. We're seeing some great shows and we've taken sidewalk cores where we have a reason to do that based upon those shows. It's a very interesting set of rocks. It's different and I won't go into much more detail than that, but we're very intrigued and optimistic that there will be areas of this overall play. It won't have the same footprint as the Haynesville. Obviously, it's a different set of rocks but it clearly is very perspective, has its own set of challenges and we're going to continue to work it. Ron Mills - Johnson Rice & Company LLC: Okay. Is the 170bs of gas in place that you all are talking about is that from the Haynesville alone and exclusive of the Bossier?

Yes.

Ron, that's exclusively from the Haynesville in that section that we cord in the EGP63. There's going to be some variability across this play and but that's strictly from that inferred from that roughly 200 foot of thickness in that thicker well bore. Ron Mills - Johnson Rice & Company LLC: Okay. I think that does it for me. Thank you, guys.

Well, listen, I think… I think we've had a few minutes here and we've gone a little long. We appreciate everybody calling in. We've got an exciting time ahead of us and if you think of something we didn't cover, feel free to give us a call and thank you.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.