西南能源 (SWN) 2007 Q1 法說會逐字稿

Good day and welcome to the Southwestern Energy Company's First Quarter Earnings Tele-conference. At this time, I would like to turn the conference over to the President, Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead sir.

Good morning and thank you for joining us. With me today are Richard Lane, President of our E&P Company and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our first quarter results, you can call Annie at 281-618-4784, and she will fax a copy to you.

Also I would like to point out that many of the comments during the tele-conference maybe regarded as forward-looking statements and involve risk factors and uncertainties that are detailed in our SEC filings. These forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results or developments may differ materially.

Well to start of with, we had a really good beginning to what we expect to be a very busy year in 2007. On the operating side we set a new record for cordially production volumes of 22.9 Bcfe, which is up 44% from a year ago. This is primarily due to our Fayetteville Shale Play, as our gross production volumes have grown to near 155 million cubic feet per day, up from about 20 million cubic feet per day a year ago. We have come a long way in understanding how to drill and complete the wells in the Fayetteville Shale as we've experimented with different combinations of fluid systems and completion techniques. We have also recently began drilling longer laterals that coupled with additional completion stages could result in better wells. So there has been a lot going -- been going on. Been a lot of R&D, a lot of learning and we'll be trying some new things as we go forward.

As many of you know the theme of our annual report this year was stimulating growth. We have already began to see stimulating growth in our production volumes and our job continues to be stimulating new ideas internally, so that our organic growth will continue. We look forward to reporting on our progress as the year unfolds.

I would like to now turn the tele-conference over to Richard for an update on our operations and then Greg for a discussion of our financial results.

Good morning. During the first quarter of 2007 we produced 22.9 Bcfe, up 44% from the first quarter of 2006. Due to increased production from our Fayetteville Shale Play, our Fayetteville Shale production was 8.2 Bcf for the first quarter up substantially from the 0.7 in the first quarter of 2006. As a result of our strong first quarter of performance, we now estimate that our second production will range between 25 and 26 Bcfe.

In the first quarter we invested approximately $301 million in our Exploration and Production business activities, and participated in drilling 129 wells. Of the 129 wells, 53 were productive, 3 were dry and 73 were in progress at the end of the quarter. Of the $301 million invested, approximately 261 or 87% was for drilling wells. We currently have 31 rigs running, 15 deep and 5 shallow rigs and the Fayetteville Shale Play, 6 rigs in east Texas and 5 rigs in the conventional Arkoma Basin.

In the Fayetteville Shale Play in the first quarter, we drilled and completed 68 wells. The wells drilled range in total vertical depth from approximately 1900 feet to 5500 feet with horizontal sections that average approximately 2100 feet. During the first quarter our time to drill to total depth averaged 20 days from re-entry to re-entry, compared to our target of approximately 15 days and as a result we drilled fewer wells than planned during the quarter. Our average completed well costs during the quarter were $2.6 million, with costs ranging from an average approximately $2 million to up to $3.3 million per well depending on the pilot area and depth of the Fayetteville Shale. We are currently drilling longer laterals with some of our pilot areas which is expected to increase our drilling days and the well cost for those wells.

Based on our activity in the first quarter, we may drill fewer wells than originally planned in 2007, but with longer average lateral length. Total number of wells drilled will also depend on other factors including the number of wells operated by others, our drilling time performance on individual wells and the total vertical depths related to the areas that we are drilling. We continue to utilize a mix of completion types across the area including conventional cemented liners, open hole packers systems, along with a combination of slickwater, crosslinked gel and hybrid frac fluid systems. Production tests during the first quarter varied from a low of 200 Mcf per day to 3.4 million per day.

In our East Cutthroat pilot area we have experienced lower than average well performance and each well there was completed with crosslinked gel fracs and further testing with slickwater and longer laterals is planned. This pilot is located within the area were we believe the Moorefield Shale and conventional reservoirs to be prospective. We plan to drill up to 7 wells to the Moorefield later this year.

Further east of this area we have completed average and above average wells that are Bull and Sharkey powered areas using slickwater systems. The Reaper #1-12H in the Bull pilot area located in the Southeastern part of our acreage, tested at 3.3 million cubic feet per day with a lateral length of 1950 feet. And in our Sharkey pilot area, located in the Eastern end of our acreage, the Wood Lumber #1-10H well was recently completed with initial potential of 3 million cubic feet per day, with a lateral length of 2800 feet.

During 2005 and 2006, we acquired approximately 50 sq miles of 3-D seismic data in the Fayetteville Shale area. Results to-date indicate that 3-D seismic data has potential to optimize well performance, minimize our geologic risks, better guide lateral length drilling and help find some conventional targets as well. We plan to acquire up to 350 additional square miles of 3-D seismic data during 2007.

Production from the Fayetteville Shale Play area is now at approximately 155 million cubic feet per day, including approximately 9 million cubic feet from conventional production and 4 pilot areas. In our press release we have provided the updated normalized average daily production for horizontal wells completed with slickwater and our crosslinked gel fluids. This has been a very busy quarter in our Fayetteville Shale Play as we have successfully ramped up our drilling activity, integrated many new people into our operations, experimented with new technology and moved forward with accessing more of our acreage. We are revising our guidance for our Fayetteville Shale production for 2007, to 47 to 50 Bcfe, up from our early estimate of 45 to 50 Bcfe.

Moving on to our conventional Oklahoma Basin properties. In the first quarter of 2007, we invested approximately $45 million here drilling 30 wells, in which 14 were productive and 4 were in progress at the end of the -- 14 were in progress at the end of the quarter. Since the beginning of the year we have put several good wells on production at our Ranger Anticline and our Midway area. As a result production from the conventional Oklahoma Basin was 5.5 Bcfe for the quarter, up 13% from the first quarter of last year.

In East Texas we continued our active drilling programs, with 3 rigs running at Overton and 3 rigs running at our Angelina River Trend Play. In the first quarter we administered approximately $48 million drilling 14 wells at Overton and 3 at Angelina River. All of these wells were either productive or in progress at the end of the quarter.

Production from East Texas was 7.6 Bcf in the first quarter compared to 8.1 Bcfe last year. This decrease in production is attributable to slowing down our drilling program a little bit at Overton while starting to ramp up our activity at Angelina River. As part of our Overton and Angelina River trend program we expect to spud our first well on our [gerbil] prospects in May. This well will be located on approximately 16,500 gross acres that we farmed in from a major company late last year.

In summary we are pleased with our results in the first quarter of 2007. We are well on our way to achieving 48% to 52% organic production growth for the year. Our Fayetteville Shale project is performing well and we expect even more improvement throughout the year. I will now turn it over to Greg who will discuss our financial results.

Thank you Richard, and good morning. Our earnings for the first quarter were $51 million or $0.30 a share compared to $58.4 million, or $0.34 a share for the first quarter of 2006. Our financial results for the quarter were driven primarily by the positive effect on our earnings of our increased production which was offset by a 15% decline in realized natural gas prices and higher operating expenses. Despite the decline in gas prices, our net cash provided by operating activities before changes operating assets and liabilities increased to $142.4 million, up 14% from the prior year period. We produced a record 22.9 Bcf in the first quarter and realized an average gas price of $6.71 per mcf, down $1.15 in mcf from the prior year period. Our commodity hedging program increased our average gas price during the quarter by $0.52 in mcf. Our current hedge position, which consists of fixed price commodity sloughs and collars provides us with support for a strong level of cash flow in 2007.

We currently have approximately 64 Bcf hedged for the remainder of the year and have hedged 75 Bcf in 2008 and 28 Bcf in 2009. In 2007 the average price of natural gas fixed price sloughs is $7.81 in mcf and the average fore price of our collars is $7.00, both of which provide a solid base for our projects while the average ceiling price of our collars is over $12 allowing us to retain considerable upside. Approximately 75% of our 2007 targeted gas production is currently hedged. Our detailed hedge position is included in our Form 10-Q which was filed earlier this morning.

Our least operating expenses per unit of production was $0.74 an mcf during the quarter up from $0.53 last year. The increase was expected, and due primarily to increase in gathering and other costs related to our operations in the Fayetteville Shale. We expect our per unit lease operating costs to range between $0.82 and $0.87 per mcf in 2007.

Taxes other than income taxes were $0.27 an mcf during the quarter, down from $0.33 in the prior year and we expect our rate to range between $0.21 and $0.26 for the full year, extending a $7 NYMEX gas price. General and administrative expenses per unit of production were $0.47 in mcf in the first quarter compared to $0.53 a year ago. The decrease in general & administrative costs per unit of production was primarily due to our increased production volumes.

We hired a total of 97 new employees during the first quarter and expect to hire approximately 75 additional employees during the remainder of the year. We expect our G&A per unit of production to range between $0.41 and $0.46 per mcf in 2007.

Our full cost -- full amortization rate was $2.24 an mcf in the first quarter and we currently expect our average rate for the year to range between $2.20 and $2.40 per mcf. Going forward, our funding and development costs and amortization rate are both expected to be heavily impacted by the timing and amount of reserve bookings in our Fayetteville Shale Play.

Operating income from our mid-stream services segment was at approximately breakeven in the first quarter compared to operating income of $1.1 million in the prior year period. The decrease in operating income was due to increased operating costs and expenses for our gas gathering activities due in part to timing differences and a decrease in the margin generated by our gas marketing activities. Operating income for our natural gas distribution segment was $9.4 million in the first quarter of 2007, up from $7.9 million in the prior year period. The increase in operating income was primarily due to weather which was 7% colder than the prior year.

We revised our production guidance for the full year of 2007 to a range of 107 to 110 Bcf equivalent, which represents a 48% to 52% increase over 2006.

At March 31st 2007 we had total indebtedness of approximately $330 million including $191 million borrowed on a revolving credit facility, resulting in a capital structure of 19% debt, 81% equity. Our $1.3 billion planned capital program is expected to be funded by proceeds from internally generated cash-flow, borrowings under our revolving credit facility and all funds raised in the public debt or equity markets. Assuming our capital program in funded entirely through cash flow and borrowings, we expect our long term debt to total capitalization ratio to be approximately 35% at year-end.

That concludes my comments and now we'll turn back to the operator who will explain the procedure for asking questions.

Thank you. [OPERATOR INSTRUCTIONS]. We'll take our first question from Tom Gardner with Simmons & Company.

Good morning guys.

Good morning.

Concerning those longer lateral that you are drilling, can you speak to that, with regards to how -- what is the incremental length there and perhaps the implication of reserves over sort of the old type well?

Yes Tom, I mean we are kind of incrementing our way up in the footage there. Doesn't show very much in the averages for the first quarter but we have begun to start doing that and -- you know what, I'm thinking we are saying longer laterals now we are talking about something more like 3000 ft, and some higher than that. If we have, say 4 to 500 ft more lateral than a previous well, that's enough to add another stage of completion and so we think certainly if we are adding stages to the lateral length at completion stages then we ought to -- we ought to see that in performance of the well and we just -- that's the data we need to collect and see that that's really come to fruition.

So you have about 20% more lateral than in your 2500 foot well and about 20% more in the way of cost associated with that, is there any sort of incremental reserve leakage on that incremental well bore? I mean, now do you think a 20% boost to EUR is in order there?

I don't think we've seen enough data to say Tom. I hate to throw a number out there. If everything is constant, which we know there is a lot of moving parts in the play, but if everything is constant then you ought to see a multiplier that's -- that's similar to the increase in the number of fracs that [you been] doing. But we really need to see that come to fruition first.

Okay. And just a question on the overall decline over at the Fayetteville. Obviously there is that deviation between the - slickwater, extra large type curve, and the actual data particularly in the first 150 days or so. Can you speak to what you see as the drivers? Is that basically unloading frac fluid or do you think that perhaps an adjustment to the model is in order?

I'm not sure I fully understand your question Tom.

Okay. On the type curves that you provide the normalized -- the normalized production data for your 151 wells decreasing through time as you have your additional well online longer, some wells fall off, but you have this average data curve, vis--vis your 1.5bcf type curves right and there is particularly an early time, there is a large deviation. Do you have any idea of what is driving that large deviation in performance versus the type curve?

Well its -- its not all that simple about the question but it is the sum of the actual data that makes up that curve and its -- those initial rates in the first 30 days is lower than that type curve. Its -- in comparison to the model curves it make it back up in some of those out days. And the sum of that I would say is we would not be adjusting the range of the production guidance we've given you per well.

I was just referring to kind of the big difference in initial rates from the normalized data and type curve that was what I was driving at. Any sense for that in just a transient part of the data? I mean just if you all had thought through that and maybe have some thoughts on that?

Well I mean we are trying to put wells on -- when they are finished being completed, we are trying to put them on as fast as we can and maybe not striving for the very highest test rate we can possibly get out of the well. We are more in a development mode here and certainly unloading fluids earlier in the well and things like that would affect some of that rate.

Yeah. I mean, maybe Richard just to add to that a little bit, and you said it earlier is that, that is the average of all the wells that we have on production. So and the number of wells that are in that data set are represented along that line. So we are drilling across a pretty broad area, we are doing different fracture stimulation type treatments in different areas. We have seen one area, which we mentioned in the press release East Cutthroat, that hasn't performed as well. So, there are a lot of things that make up -- that go into that data set and its hard to pin down one single aspect to it. Which is, and I know it's frustrating for you guys, its frustrating for me here as well. But, for example, of the 15 deep drilling rigs that we have drilling, those are drilling I think today and in 12 or 13 different areas and so, we have the potential for variable results coming through the data. And you know, its new to a number of things, it's new to the areas we are drilling in, it's new to the fracture stimulations and the effectiveness of each one of those. And we need to get more wells in each area and then at some point we can begin to understand, within one area of this play we will be able to better understand what's going on. But when you're spread across 80 miles and 40 miles the other way, this is just a sum of all of it.

Okay. Well forgive the tedious questioning. I'm just trying to comprehend what's going on here.

I mean we understand that and it's a good question and the book continues to be filled out. And we don't have all the answers yet.

Well thanks guys.

We'll move next to Scott Hanold with RBC Capital Markets.

Thanks, good morning.

Good morning.

Could you just talk a little bit about the average flow cost? I guess you talked it was about 2.6 million in the Fayetteville Shale on average in the first quarter. Can you kind of just give an idea of how much of that could be the result of drilling these longer laterals and is there anything else sort of impacting that?

Scott, I think the biggest driver in the first quarter was, we had a lot of wells in the quarter where we were out in little less controlled area, in the far southern edge of the play and still learning some things there. So not as much built in practices in that new area that affected our costs. We are using oil-based muds on a lot of those wells which adds to the cost and we will see if that's a practice that we are going to need to utilize long term or that's something we can get away from, rather than casing programs and things like that.

We've had issues with the wellbore stability, we've had wellbore stability issues challenging things in the play throughout it, but maybe a little more so in the first quarter in those areas. Which really -- this translates into higher potential for hole problems. All those things kind of come into play. I would say really to be fair also we've got all those rigs up and operational and fully crewed and staffed but there is some -- there is some aches and pains going through that and not all those crews are operating at the level we would like them to and we are having to emphasize what we think the best practices are for drilling all those wells. But with a 350 person subsidiary there that's new and all those best practices have not been drilled home completely yet and I think that has affected well performance as well.

Excuse me. So is it fair to say that I guess going forward, you still see probably a pretty decent range in expectations and sort of some efficiencies overall?

Well I think our expectations will always be that, till they get -- till they come to fruition. Quarter to quarter is a little hard to say but we are certainly going to drive toward that this year and I think our team will show that they can increase drill efficiencies as the year goes on and that should help on the cost.

Okay, thank you.

We'll move next to Brian Singer with Goldman Sachs.

Thank you. Good morning.

Good morning.

Kind of going back to the first question, production was very strong out of the Fayetteville in the first quarter, yet kind of as mentioned it looks like the average new well in the past two quarters seems to have had slightly weaker performance than the previous quarters, I guess. How do we reconcile -- how do we reconcile this?

Well I think we have -- we have a larger number of wells entering that set than some of the new areas where we have really honed our best practices for completions and what the best recipe for that completion is. And then in areas where we've drilled a lot of wells and we've had a chance to kind of treat the recipe for a given area and had a chance to hone in more on what the really best practice -- completion practice is to get the most out of those areas. So I think it has to do a lot with new areas and learning what's best for those new areas.

And was there any was there any change in timing when you brought wells on line versus your any sort of expectation? And I guess along those lines can you comment on what your expectations now and your guidance for a slight decline in production there in Q3 and Q4?

I don't think there has been a fundamental change on the first part of your question, I don't think there has been a fundamental in days between when a well is ready to be completed and when it's put on production. It's highly variable I know you know that Brian, we've talked about that in the past and how stepped out that location is, but I don't think we see a big coloration between the number of days it's waiting and the performance. So, I wouldn't attribute -- attribute it to that. On the guidance things that you mentioned your second question there, I would say that we did drill less wells than what we expected in the first quarter because of some of those issues, and although the production is up in the first quarter, we are pretty much on track with our number of wells completed. So, its kind of good news, bad news maybe will be a few less wells in Q3 and 4. But we actually completed about the takes we would like to actually dug into our inventory there which is our wells waiting on completion. We've reduced that inventory some, so that's a good thing.

And then Q3 and 4 will be where the -- effective, a little bit lower, our first quarter wells will wash through the program and affect maybe affect some of the production.

Thank you. And then lastly, there is the East Cutthroat results that all changed the risk profiles where the Moorefield Shale, or do you see this as unrelated?

I see it as unrelated because we just don't know enough about the Moorefield Shale. We're getting into start into some more of that work for the Moorefield and we'll try to assess it for what it is. I think we've started on our second horizontal well there now. And then, so I don't see them as tied and then East Cutthroat, we are just -- we are trying to point out for you where we are seeing some variability and where we have it. Some statistical meaningful body of wells that we can say, "okay there is 8 or 9 horizontal wells," I think there are 9 now producing and -- they are pointing to something that's left and what our typical average well is. It's pretty darn small area but nonetheless we try to point out some of the variability and we have enough wells to pinpoint one area we are trying to tell you about that.

I don't see it tied with this Moorefield and I don't see that we've got the answer there either. There is a lot of things that we are trying to do there, we did a lot of wells with -- mostly all our wells there with cross link fluids, with gels, and our team is -- everybody doesn't agree on what's the cause and effect of all that is, what we do know is we did mostly the wells with that and we obviously want to try some with slickwater and we want to push the laterals out there and see what results we get.

Great. Thank you very much.

We'll take your next question from the line of Marshall Carver with Pickering Energy Partners.

Yes. A couple of quick questions. On the fist quarter, if you completed the say number of wells that you are expecting, do you say it was well productivity that contributed to covering in above the high in the guidance there?

Yes I would say, I would say that we basically -- our average well is and it's written more than one quarter. Really Marshall, if you think back about this is the wells we drilled in Q3 and 4 of '06, that have really flowing through, and providing that production boost. It's a fast moving project and a lot of variables there but for the [paper] I would say that it more has to do with [inaudible] drilled late last year than the ones in the first few quarters of '06. And then in total -- '07, I'm sorry. And then in total as a company we had a nice boost from [inaudible].

Okay. That's helpful thank you. And then on the longer laterals, would you expect the cost to be higher in 2Q compared to that $2.6 million cost for the more recent wells, should the bill go higher than that, for the second quarter?

Well there is some benefits, there is some things affecting the cost upward and there is some things affecting the downward and I'm thinking with some of the improvements we're seeing, we also negotiating the forward quarters on pricing for some of our key services and things. And we've seen some ground there. Something fast helping, I don't see them moving a lot from what we've reported here. If we keep pushing out an [adding] first stages and we could see that go up. We would have to see the well performance to justify that.

Okay. Thank you. Good quarter.

Thanks.

We'll move next to Jeff Hayden, Prichard Capital Partners.

Hey guys. Some questions on some of the science you guys are doing out there. You've been testing a whole bunch of different completion techniques, why don't you give us any color on whether you've seen anything physically significant differences, with you know, the slick watr one versus crosslinked gel etc, etc. and then sort of a follow on to that, people who are testing all sorts of stuff in the Barnett Shale. We dual lateral, [symo frac], things like that and getting pretty good results. Do you value any use of that in the Fayetteville at all?

Yes Jeff, we are. Personally I'm very interested in the potential positive of effects of what people are describing as symo frac. Not only from well performance but also from above the ground efficiencies that can come with centralizing your operations and things. The great unknown is how much would that help well performance. Several operators are talking about doing that and that's helping them in the Shale place. And we see some potential benefits from doing that. We've just started doing a few of those so we don't really have an answer to report on that but its something we definitely want to pursue. And I think -- when I think about the whole subject, the simultaneous fracing of Arab wells, has the chance -- you know my hypothesis and I think some of our teams hypotheses is that below the ground from a performance stand point it has a chance of creating a better overall network of fractures, enhanced fractures that should affect overall production and drainage.

Okay and on the completion techniques, the slickwater crosslink gel seeing -- see any differences there which are making you kind of lean toward one or the other?

Well, there's some debate really even entirely on that what we think the best is. We are working hard to try to sort that out. You know notionally I would think that slickwater is the way to go, there's some data that supports that. When you build in some geographic bias like East Cutthroat you know it was almost all crosslinked gels and are they -- they are adding to the database that we are trying to differentiate. It's not entirely clear now, my personal opinion is that we'll end up with slickwaters wherever we can possibly do them. You know, the other play is that it seems to be that, it seems to be the completion technique that's has risen up. It doesn't mean that in our basin in our new play there's some inherently different things that could affect that but you know we would be driving I think towards slickwater where we can do it. We've had places that we've chosen not to do it because the crosslinked gels allow us, we've had some trouble with treating pressures in certain areas and the crosslinked gel seems to help us overcome that but we don't have a clear answer on that as we'd like but that's my two cents of where I think its heading.

Okay and then one last question. It looks like the whale has become sort like a humpback whale. I wonder if you can talk about that new area. What kind of results are you seeing there and about how many additional locations do you think you've added.

The area that we -- where the hump came from was the west cut-throat area, and I think the shaded area increased something like 30 to 40 thousand acres based on that, so again with 80 acres facing you can kind of do the math on how that would turn out. It's quite a few additional wells if that's all like what we've seen inside that pilot. And the well that we've seen inside that pilot was a good well was a Green Bay 121 well, it's waiting on the pipeline but it tested a little bit above 2 million cubic feet per day. And so that's -- when we look at that we say we've got a pretty darn good well, it's tested solid and so we are trying to envelope that area in.

Okay guys thanks a lot.

We move next to Jason Gammel with Prudential Equity.

Good morning guys, thanks for taking the question. I'm looking at the time to drill re-entry to re-entry are going up by about two days in the quarter, from eighteen to twenty but you're maintaining a target of 15 days. Now, I could probably attribute the incremental drilling time to the longer length of lateral but if that's the case, is the 15 day re-entry to re-entry goal still valid?

Well I think it depends on where we are drilling and what the true vertical depth is where we are operating and it's going to vary based on that quite a bit.

For example from the Scotland area you're looking at 1,900 feet of depths and down along that Southern interior you're looking at some in excess of 5,000 feet deep. So what's going to come through the numbers is always going to be the average or sum of where we are drilling which is going to change across the board. If we focused all of our drilling in the deeper part of it we are going to be at a longer average time than we are if we up in the -- where the shale is shallower. Just a question of total days as well and then the lateral lengths can extend the time out additionally

And then Harold you said in the first quarter you were essentially at the long end of that range because of where you were drilling and the depths you were drilling and again that a 15 day re-entry to re-entry target is still going to be valid over a longer term?

Well I don't know but on the average but that's our target right now. It was our target in the first quarter which we did not achieve. I asked somebody here this morning what percentage of our wells were drilled in the deeper part of it in the first quarter. I just didn't happen to get that information before we started this so that I could answer that.

Okay, fair enough. And maybe if I just ask a question that's already been asked one more time in a little bit different way. For a go forward purposes we should expect 2.6 million per well is a pretty reasonable run rate. And should we recognize that 1.4 Bcfs per well is still more or less what you're looking at but there's the potential for upside because of the incremental lateral length you're drilling?

Yes, I would say that that's -- I mean the way you have described it there is accurate.

Okay, thank you guys

We will take our next question from Richard Moorman, Capital One South coast.

Good morning. First let me say congratulations on the excellent production from a year ago especially. Second, I had a few questions if you can help me understand a little more the make up of your drilling program right now. First, Richard you have talked previously about moving into new pad drilling in some areas, I am just curious if you can give a feel for how many of your wells are now being drilled on pads.

You mean multi-well pads?

That's correct, yes, sorry.

There's the -- they are very few percentage Richard of the total where that's happening right now. We've done probably less than 6 wells that way I would say and we are trying to -- we are working on that, we are trying to understand how best to drill the shallow part of the hole which is going to involve turning laterally as well as vertically so we are calling them tunnel zonal wells. I only have to get down there and build the curve later in the well but we are actually having to push it out early and get away from the other well bore. And we are just trying to see what the--how the best way to do that is. The first ones that we've done there we didn't see a big efficiency and that's not surprising. Trying to get the bugs worked out on how those shallow rigs and deeper rigs are going to interact on those holes. So we have not done very much of those. We are trying some of those in East Texas now as well and we hope there will be some cost savings there.

Okay super.

We are going to keep driving at that. It's an important part to try to understand in our development scenario.

I've never found you to shy away from innovation. So going ahead then with your percentage of drilling now in the new areas I mean you have got so many pilots underway still on the Eastern and Northern side, can you give me a feel for how many of the new wells are still, say targeting areas where you might have only a few wells as opposed to how many wells are really going into areas you have more confidence or a track record in.

I don't have those specific numbers sitting in front of me Richard. We can maybe get those for you, I don't want to give you a number I am not sure about. You know the greater majority of the wells from this point forward in '07 will certainly be in areas that we have more history and more infrastructure.

But even having said that its often times its not like we are drilling an 80 acre space well. We are drilling in many cases, in most cases I think we are drilling in new sections so we are not as much drilling 4 wells in one section or 8 wells in a section as in a development program. Depends on who you are talking to and how people think about it but like in that East Cutthroat area I think we have 6 wells there and each of those was in a separate section of land, so those were basically one well per 640.

So you know when you asked the question about multi-well pads and stuff like that, we are not at the place that they are in the Barnett where each individual little Company has got just you know X amount of acres and they are going crazy developing it like on 80 or 40 acre spacing. You know we are still in a situation where we are spaced way broader than that. So when you step a mile away even within a field you certainly don't get the economies of a multi-pad operation. Then you may get variability that you otherwise wouldn't anticipate. And I think that's an important thing if we are drilling here like you cant emphasize it enough, we are drilling here across a very, very broad area and so we are still spaced out long distances apart.

Super and still managing to beat everybody's guidance. Hey, last thought on the air drilling, just wondering this is a technique that has been talked about in a lot of places, East Texas who's tried it, Woodford I guess they are experimenting it even the [floyd's sale's] been commentary. Just wondering what your thoughts are on the practical applications that they are drilling in the Fayetteville.

The air drilling is something that's taken place forever in the Arkoma Basin that's how all the wells have been drilled basically through the [inaudible] age rocks where the conventional completions are. And so that's what we do in drilling the vertical part of the hole. Those small rigs use air to drill with and then we use a mud system once we get into the [moral] shale and that's necessary just to keep the hole open and at least as we know it at this point, Richard talked earlier about some parts of the play and it tends to be generally I think where we're deeper -- deeper than 5,000 foot depths where we are doing some moral based mud systems just for hole stability associated with the plays that you cut through in the rocks. I don't know if there is potential to do air drilling in this Fayetteville section but I would suspect our drilling guys are turning over in their sleeping bags right now if they kind of hear us talking about that.

Fair enough. Well thank you again and congratulations on a great quarter, I look forward to the second. Thank you.

We'll go next to [Nicholas Pope], JP Morgan.

Hey guys. I had a quick question, I was hoping you could expand a little on the conventional Arkoma wells that you've been drilling in your Fayetteville acreage. I guess I was hoping to hear a little bit about kind of potential from the co-mingling in the same well bore you used to use for the Fayetteville and conventional Arkoma etcetera -- costs.

Well, Nick, the conventional targets that we're encountering is pretty exciting and it's a nice kind of good thing to be happening that we really did not count on. They are a token [moraine] age type sands which are not too dissimilar from what we've produced historically back in the traditional part of the basin and what we call a fairway -- the producing part. So we are seeing some of those intervals show up productive and we've seen some really nice production from them, similar to what we see over there in that part of the basin and frankly, more of them are showing up and producing better that I would have thought at this stage in the game so its just a nice upside for us.

The co-mingling question, part of the question, basically what we are doing now is in that vertical part of the hole like Harold was talking about. We are drilling that down on air pretty fast, if we see a conventional target usually shows up in that part of the hole and we usually get a really good look at it because we are on air and we get a good sign that it is present and gas productive. And we've been basically stopping and making those into conventional producers and then we can drill another Fayetteville Shale well very close to that and go on down the road. So right now that's probably the best thing for us to do and then long term we can look at co-mingling or if we have zones behind pipe after we have completed a Fayetteville well.

Are you finding the prospects through drilling or is it through the traditional 3-D seismic data you've gotten.

Yes, I'd like to claim high technology as a cause but I think right now its been putting so many holes in the ground we are hitting them, but on the same note though, we do have some encouragement from the preliminary work that we have done and what we ought to be able to see with the 3-D that some of our teams thinking it might be a nice guiding tool for more conventional production and exploration.

Any idea what kind of area would be his perspective at this point? The conventional stuff on your Fayetteville acreage?

Not really right now we've seen it and I think four or five to pilot areas. So, not really.

That's it. That's all I had.

Thanks.

Thank you.

Operator; We'll move next to John Gerdes, SunTrust Curtis Group.

Thank you. Richard, what do you - in those four pilot areas you've mentioned the conventional work - what percentage of these wells in the vertical section are you actually seeing this perspective of [inaudible].

What we have, you know, I don't know the total count that - we have more than the four good producers, have seen some of the shallow zones, maybe they have been thinner and some other wells are not as good as shows and so there's another handful of wells besides the producers that have seen some evidence of conventional production. Maybe we've seen it in something like 8 or 10 wells some sign of some more conventional zones present, we just have the four producers on though right now I think.

How many vertical wells in that area, 20 or 30 or so--?

I don't know that exact number.

But you're not seeing it..?

Not seen in every well.

Every well

Right. And I wouldn't expect if its even over in the fairway where we can have a lot of well control. This can be fairly channelized phases and move around on you and - we are not talking about big blanket sands.

What are these? These are essentially channels, aren't they?

Yeah they are. They are shallow marine, tri-deltaic sands and if they are like they behave where we have more well control, they tend to be more dip oriented bodies and so, which means where we are drilling they are going to be North, South plus or minus 30 to 40 degrees of depositional change there and there can be a [lose] of define that can be very narrow and you can think you are offsetting well North or South and it not be present but we are pretty good at that so if we get into an area that's - we can get our teeth into it, we know how to chase it.

How are the decline profiles looking, I mean, I know you -- it's early the days off the volumes but..?

It's pretty early.

I mean, there, really don't have much data at this point I guess .

No.

Okay. You mentioned oil based mud using that some of this lateral, I guess, and Harold had mentioned maybe in some of the deeper section of the Fayetteville you are working for formational reactivity. Are you -- what's the cost implications, are you picking up, are you using PVC bits in that situation, are you picking up key rate additional penetration rates. How much more costs are we looking at there.

I think the cost of the mud, when we go to oil based mud, I think we are probably somewhere in the 2 to $300,000 cost range.

Incremental cost?

Right. And its - what happens is its you pay me now or pay me later where we have a little bit more upfront deciding we are going to be oil based yet the stuff out there we need for that, pay for the incremental chemicals and all that kind of stuff and then basically see a more stable well bore, less problematic well bores, easier to clean horizontals and so the cost savings a little harder to pin down but we are lowering the trouble costs. And then you know we are looking at some other technology to - we are just starting to scratch the surface on looking at drilling with casing, I've seen that that's a technology that we can bring to bear on the play and some other things.

You're running - you're not running liners, you're running casing back to surface on those lateral sections, aren't you?

Most time we are running liners.

We're running liners. Shifting gears on your stimulation, what kind of sand loading are you doing per stimulation and how many stages, I think if you kind of migrate it to, are you doing 3 per these laterals a little over 2100 ft or is it 4?

We've been in the 4 to 5, probably more likely we've been at the 5 stages. Its been kind of our norm and we are putting about 1 million pounds of sand away in those stages.

In aggregate, right?

Correct.

Okay. And the cost per stage, what are those costs running you per stage?

Now, they are about -- It depends exactly what we are doing.

Fair.

2 to 250,000.

Okay. Richard, thank you very much.

We'll move next to Christopher George, Capital One South coast.

Good morning gentlemen. Just a couple of quick housekeeping items. Did I get the production per area, I get to the Fayetteville Shale 8.2, these for the quarter and [Eastex] at 7. 6, just want to confirm that, and then I want to hit Arkoma in the Permian Basin as well.

Yes, Chris you've got those 2 right and then the Arkoma would be 5.5 Bcf for the quarter, Golf Coast 0.4, Permian Basin 1.2

1.2, did I get the right thing here in 5 rigs in Arkoma? Or was I off there?

That's correct.

That's correct. And then I will throw you a curve ball real quick with the Angelina Trends, want to get some more results there and see what - see how things are going.

Okay we are just really, we're not allowed to well to report on yet there for the first year, while we are kind of looking for I think our model well would be -- about a 1.5 Bcf, 1.4, 1.5 Bcf well. Travis Peak well and testing somewhere 2 to 2.5 million a day type if you look historical at what we've done. And we are drilling our -- we are getting started on that [Gebble] block which is an exciting block of pretty nice new acreage block we have there.

And you gave a gross acreage. What's your net there?

I'm not exactly sure on what that number is.

Okay, I'll follow up with Bill at that later. And that's basically all I have today. Thank you.

We'll move next to Gil Yang, Citigroup.

Good morning. I just wanted to go back to this issue of, and I think Harold you've already said a couple of times you'd know, but the 60 wells -- any ideas the proportion in the new area versus the old areas?

I think we are probably greater than 50%, Gil on the first quarter.

In the new areas?

In the new areas.

Okay. For the well that you were drilling, the old areas, are you still comfortable the costs are within the 2.2, $2.3 million range? Those costs have not gone up, its more of the new wells that has gone up with costs. Is that...?

That's correct. The [earth] and so when we say 50% then we are saying okay, newer to a large extent was deeper in the first quarter but much of those numbers, but we have areas in that. I hate to call them historical because its also new but we have areas where we've done a lot more drilling, add more infrastructure that those costs are coming in -- some of those coming in below that range you just gave. And some of those days re-entry to re-entry have been less than 10 days. We are trying to look at the whole picture and model it and give you the best guidance we can.

Right okay. In the case of the newer areas, obviously the well costs are higher because you started doing more experimentation if you will, looking around and figuring what's best. Would you say that at the same stage of development for these older areas, were the wells cost similar, given then the place would have gone up as well but are you seeing the same sort of learning curve costs in the newer areas as you saw in other areas or are these -- we expecting more learning [cut] of costs in these new areas than before?

I think it's similar. I think if you go back to some of the earliest drilling there we did, we went through a learning curve and then we tried to convey to you as we got better what the most recent costs were. But certainly we went through the same learning curves and I would say, you copy out of that with a qualitatively both of them moving with inflation. So, but I would say yes. It's a similar type situation. And then as we add laterals to it that's kind of a -- maybe that's the incrementally different piece.

Gil. I think we need to be clear that its just not newer versus older, it has to do with the depth we are drilling at versus -- shallow versus deeper. Where the Shale is deeper its going to be more expensing so if your -- in your mind in your question you are combining newer areas with deeper areas you could be -- be pulled by newer versus older because its deeper versus shallower.

Okay.

You know what I'm saying? So the mix and when you consider that the Shale, or drilling somewhere else better, this is what I'm saying 1900 ft deep, we are drilling some that are 5,000 to 5500 ft deep. That's twice as deep. It also is pushing if you think about it, is pushing as we move to the south and east we are pushing towards the area in which Chesapeake's wells have been and that they've had higher costs, so and using oil based mud which is in. So you have got to think about what you are physically doing here.

Are you getting to the deepest portions of your acreage or is there still some stuff that's deeper.

There is some that's deeper, yes to the south.

Okay and now, do you have any indications yet whether or not the recoverage will be higher at those deeper depths?

We don't have a conclusion on that.

Well, based on the data you've seen so far can you make some preliminary comments?

I can't. Richard maybe you want to venture something on that.

I mean, the depth relationship all to itself, if you just that East Cutthroat's in one of the deeper areas and so that -- and that format's there right is not what we'd like it to be, we will ultimately get better but, so our example there of deeper is not what you would think. If you just take how does depth play into the whole equations, it should be -- it should be -- it should help. Now that's not talking about costs or economics its just talking about packing gas in place.

Rich, I'm sorry did you say what's East Cutthroat are produced at, what the recovery seem to be versus the other areas?

No we didn't talk about the recoveries, just -- the -- the average well there is less than what we've seen in other areas.

Are they still big enough to be economic or not?

I would say we are not out of the woods there, no. We have a pretty high threshold that we want to achieve, I think you know that. And we are not getting it in that small area right there for sure but that's why we want to try some slip water completions then we want to try some watery laterals. What I wouldn't infer is that the deeper is worse that any kind of the global or that's its better. That's what I said in the beginning is that I don't think we can say that because it's deeper its better, we'll have better performance or worse performance. Its probably going to wind up being related to fracture stimulation effectiveness and the rock type that's there, the rock that's there.

Okay, it's just a different kind of challenge.

And the thickness that's there. I mean you've got all of these different moving parts across 80 mile wide area and the shell's not the same thickness across it. If we had the answers Gil, we'd just give them to you. I think in other words we just - there's a lot of barrier [boles] and we don't have a complete conclusion on it. So we darn sure know that these Cutthroat area is not as good as some of the other area, and that not - I think will not be unexpected across this play. We'll find some areas that aren't going to work too well, at least by what we are currently doing, there may be techniques we can use that will improve them and it doesn't mean that over time it won't work. Point is for what we are seeing right now, these Cutthroat is not looking at that little area about 4,000 acres isn't looking too good to us. I think our east Cutthroat we drilled about 6 wells on a mile of part each so we've got more assessment to do.

Okay, last question is; for the moment is that it sounds like the 300 million is still on track for the end of the year for exit rate?

Yes. We're not really changing that. Its kind of a goal we have for ourselves and we've said we basically thought we could get near that number for the year end and that we are still driving towards that.

Okay. Richard as - we've done some discussions about the decline curve earlier with lower IPs that certainly shallow decline rate versus the tight curve. From your perspective the hitting it at whatever target or whatever goal you have, are you helped or hurt net between the deposit of the slower decline rate but the negative of the lower IP.

Well, it depends on what you are talking about, if you are talking about the near term production --

The time you're getting a 300 exit rate.

Well, near term production you rather have a higher rate in terms of estimated ultimate recoveries and things maybe you may conclude some thing differently but we really have to be careful with those curves we put out there and the way we do our work is by assessing every single well onto itself. Its just a compilation of all that - all those wells put in one place.

Let me say this about 300 million exit rate. That's not our - I mean lets not get tangled up about what our objective is here, our target. We've tried to give people a guidance so as to where we think we could be on this thing by year end and that's for 300 million a day. You there's a lot of other objectives and targets out here and the main target is to figure this all out, to do it right, do the right things and achieve the PVIs that We want to achieve and so that's what still going to guide our activity. We are not going to do everything we can to get the 300 million a day, at least that's not my objective for it but you call it a target, maybe its just a terminology but that's just a guidance as to where we think we have a good chance of reaching that but there are a lot of things in between here and 300 million a day that's going to occur.

Okay, fair enough Harold. Appreciate the comment.

[OPERATOR INSTRUCTIONS] We'll move next [Phillip Benz], Buckingham Research.

Hallo

Hi Mr. Benz, your line is open if you have a question. We'll move next to Michael Scialla with A.G. Edwards.

Hi guys. On your 181 wells that go into that composite curve. Can you tell us what percentage of those have been drilled with lateral say longer than 2500 ft at this point.

Mike, it would a very small percent, I don't have that exact number but--.

Less than 40?

Oh yes.

Okay, and then kind of along the same lines if you are trending toward longer laterals does that -- that bears out to -- if that works out is it safe to say that the 400sq of 3-D that you are planning are going to be key to going to longer laterals or -- I'm just trying to get a sense, do you need the 3-D to be more confident enjoying the longer laterals or is the 3-D a necessity in just certain parts of the play given the complexities of various areas?

Well I think it is going to be -- no doubt in my mind it is going to be a beneficial tool towards more efficiently drilling longer laterals and having less, you know, getting out there partway and getting lost or leaving your target or incurring something that you couldn't anticipate. So, I think it is definitely be a better -- it is going to be an improvement tool that will allow us to be better at that. No question about that. And then you know, where we are doing them I don't think we have to stop -- we are not going to hold still, stop and wait on that data, we have some data, we have some areas where we have more well control that we can pursue it now and then we will have to maybe have to use some pilot holes in areas that we don't yet but, it doesn't mean we are going to wait before we get all the data to start that but it definitely will be a good tool to help us.

Is it likely you go beyond the 400 sq that you are thinking about now?

Well, we will just have to see. You know, I don't want to guess what that is going to be right now but if it turns out to be economic tool that is the key. We know we can make better maps and all that but we have a big investment in the data too. So, if it turns out to be economically beneficial then we would probably utilize it anywhere where we go to develop.

I guess one of those might be the 2.6 million for the wells drilled this quarter, very first quarter. I assume that does not have any allocated seismic built into it?

That is correct.

Okay. Thank you. Go ahead.

[OPERATOR INSTRUCTIONS] We'll go to [Phillip Benz], Buckingham Research.

Bob Christensen speaking at Buckingham. About 3-D seismic...

Bob, can you speak? We've got trouble hearing you here.

Yes, Harold. Can you hear me?

Yes.

The 3-D seismic, sorry, is it, is the resolution I guess the word, set for the Fayetteville or will it illuminate to depths, you know, 15, 16, 17 thousand feet down?

No it is not. The design of the acquisition perimeters are not set around imaging that deep, Bob.

Okay.

There are -- I would say it is fair to say they are more centered around the Fayetteville but what that is going to do is it is going to give you a high quality data from the surface -- near surface down to the Fayetteville and it is going to give you some high quality data below the Fayetteville where there are some other targets. But not -- it is not shot to image super-deep.

So is Anadarko that excluded?

If I was to say, I would say nothing has been excluded. There is a lot of targets that actually come into our field of view with that data. So, I wouldn't say we are excluding anything.

Because I remember from the Fayetteville Geologic Society, the Arkansas Geologic Society, they had some dots on the map sort of out to the east of [are buckle tests] down in the 70s and I think they were dry-holes largely, but will that be a possibility for you guys down the road?

Well, I would -- It is always a possibility. I wouldn't say it is way up there on our priorities.

No.

we have some -- we have the conventional sands shallower and then we have some deeper carbonates but not a lot deeper, that are certainly exploratory but not as the great unknown as say the Anadarko might be. And then there's places where the Anadarko wouldn't be as deep as some of the areas that you've commented on, Bob.

Well, great. Thank you very much.

We have no further questions at this time. I would like to turn the call back over for any additional or closing remarks.

Well thank you for being with us today. I know it is a busy time for everyone so we are going to wrap this up and see you next quarter.

That does conclude today's conference. You may now disconnect your lines and thank you for participating.