Southwestern Energy Company Q1 2007 Earnings Conference

Tuesday, May 1, 2007

Officers

 Harold Korell; Southwestern Energy Co.; President, Chairman and CEO

 Richard Lane; Southwestern Energy Co.; President E&P

 Greg Kerley; Southwestern Energy Co.; CFO

Analysts

 Tom Gardner; Simmons and Co.; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Jeff Hayden; Pritchard Capital Partners; Analyst

 Jason Gammel; Prudential Equity Group; Analyst

 Richard Moorman; Capital One Southcoast; Analyst

 Nicolas Pope; JP Morgan; Analyst

 John Gerdes; SunTrust Gerdes Group; Analyst

 Christopher George; Capital One Southcoast; Analyst

 Gil Yang; Citigroup; Analyst

 Philip Franz; Buckingham Research; Analyst

 Michael Scialla; A.G. Edwards; Analyst

 Bob Christensen; Buckingham Research; Analyst

Presentation

Operator:  Good day, and welcome to the Southwestern Energy Company First Quarter Earnings Teleconference.  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.

Harold Korell:  Well, good morning, and thank you for joining us.  With me today are Richard Lane, the President of our E&P company, and Greg Kerley, our Chief Financial Officer.  

If you've 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'll fax a copy to you.  

Also, I'd like to point out that many of the comments during the teleconference may be regarded as forward-looking statements that 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 off with, we've had a very good beginning to what we expect to be a very busy year in 2007.

On the operating side, we set a new record for quarterly 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've 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've also recently begun drilling longer laterals that, coupled with additional completion stages, could result in better wells.  So there's been a lot 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 begun 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, and we look forward to reporting on our progress as the year unfolds.

I'd like to now turn the teleconference over to Richard for an update on our operations and then Greg for a discussion of our financial results.

Richard Lane:  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 in the first quarter, up substantially from the 0.7 in the first quarter of 2006.  As a result of our strong first quarter performance, we now estimate that our second quarter 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 in 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 1,900 feet to 5,500 feet, with horizontal sections that average approximately 2,100 feet.  During the first quarter, our time to drill to total depth averaged 20 days from reentry to reentry, compared to our target of approximately 15 days, and as a result, we drilled fewer wells in plan during the quarter.  

Our average completed well costs during the quarter were $2.6 million, with costs ranging from an average of 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 in some of our pilot areas, which is expected to increase our drilling days and the well costs 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 packer systems, along with a combination of slickwater, crosslinked gel, and hybrid frac fluid systems.  Production tests during the first quarter have varied from the low of 200 Mcf per day to 3.4 million per day.  

In our East Cutthroat Pilot area, we've experienced lower-than-average well performance.  Initial wells there were completed with crosslinked gel fracs, and further testing with slickwater and longer laterals is planned.  This pilot is located within the area where we believe the Moorefield Shale and Conventional reservoirs to be prospective.

We plan to drill up to 7 wells to the Moorefield layer this year.  Further east of this area, we have completed average and above-average wells at our Bull and Sharkey pilot areas using slickwater systems.  The Reaper #1-12 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 1,950 feet.  And in our Sharkey pilot area, located in the eastern end of our acreage, the Wood Lumber #1-10 well was recently completed with initial potential of 3 million cubic feet per day, with a lateral length of 2,800 feet.

During 2005 and 2006, we acquired approximately 50 square miles of 3-D seismic data in the Fayetteville Shale area.  Results to date indicate that 3-D seismic data has a potential to optimize well performance, minimize our geologic risk, 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 in four 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 assessing 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.  

Moving on to our Conventional Arkoma Basin properties, in the first quarter of 2007, we invested approximately $45 million here, drilling 30 wells, of which 14 were productive and 4 were in progress at the end of -- 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 Arkoma 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 invested 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 Jebel prospect 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.

Greg Kerley:  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 in 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 hedged position, which consists of fixed-price commodity swaps 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 our natural gas fixed-price swaps is $7.81 per Mcf, and the average floor price of our collars is $7, 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 up side.

Approximately 75% of our 2007 targeted gas production is currently hedged.  Our detailed hedged position is included in our Form 10-Q, which was filed earlier this morning.  

Our lease operating expenses per unit of production were $0.74 per Mcf during the quarter, up from $0.53 last year.  The increase was expected and due primarily to increases 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.

Tax, other than income taxes, were $0.27 per Mcf during the quarter, down from $0.33 in the period year, and we expect our rate to range between $0.21 and $0.26 for the full year, assuming a $7 NYMEX gas price.

General and administrative expenses per unit of production were $0.47 per Mcf in the first quarter, compared to $0.53 a year ago.  The decrease in general and 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 pool amortization rate was $2.24 per 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 finding 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 Midstream 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 activity 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 31, 2007, we had total indebtedness of approximately $330 million, including $191 million borrowed on our revolving credit facility, resulting in a capital structure of 19% debt and 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/or funds raised in the public debt or equity markets.

Assuming our capital program is 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, so now we'll turn it back to the Operator, who will explain the procedure for asking questions.

Questions and Answers

Operator:  Thank you.  We'll take our first question from Tom Gardner with Simmons and Company.

Tom Gardner:  Good morning, guys. Hey, concerning those longer laterals that you're drilling, can you speak to that with regard to how -- with the incremental length there and perhaps the implications of reserves over sort of the old-type well?

Richard Lane:  Well, yes, Tom, I mean we're -- we're kind of incrementing our way up in the footage there.  Doesn't show very much in the averages for the first quarter, but we've begun to start doing that, and with -- I think when we're saying longer laterals now, we're talking about something more like 3,000 feet and some higher than that.  If we have, say, 400 to 500 feet more lateral than our previous wells, that's enough to add another stage of completion, and so we think that certainly if we're adding stages to the lateral length, the completion stages, then we ought to see that in the performance of the well, and we just -- that's the data we need to collect and see that that really comes to fruition.

Tom Gardner:  So you have about 20% more lateral than your old 2,500-foot well and about 20% more in the way of costs associated with that.  Is there any sort of incremental reserve leakage on that incremental well bore, or do you think a 20% boost to EUR is in order there?

Richard Lane:  Hey, I don't think we've seen enough data to say, Tom.  I hate to throw a number out there.  If everything's constant, which we know there are a lot of moving parts in the play, but if everything's constant, then you ought to see a multiplier that's similar to the increase in the number of frac stages you're doing, but we really need to see that come to fruition first.

Tom Gardner:  Okay.  And just a question on the overall decline curve of the Fayetteville.  Obviously, there's that deviation between the slickwater and 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 at basically unloading frac fluid?  Or do you think that perhaps an adjustment to the model is in order?

Richard Lane:  I'm not sure I fully understand your question, Tom.

Tom Gardner:  Okay.  On the type curve that you provide, the normalized production data for your 151 wells, decreasing through time as you have your additional wells online longer, some wells fall off.  But you have this average data curve vis-à-vis your 1.5 Bcf-type curve.

Richard Lane:  Right.

Tom Gardner:  And there's -- particularly in early time, there's a large deviation.  Do you have any idea of what is driving that large deviation in performance versus the type curve?

Richard Lane:  Well, it's -- not to oversimplify the question, but it's the sum of the actual data that makes up that curve and those initial rates in those first 30-day is lower than that type curve.  In comparison to the model curves, it makes 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, the EUR per well.

Tom Gardner:  I was just referring to kind of the big difference in initial rates -- apart from the normalized data in the type curve.  That's really what I was driving at.  Any sense for that, just the transient part of the data?  I mean just if you all had thought through that and maybe had some thoughts on that?

Richard Lane:  Well, I mean we're trying to put wells on -- when they're finished being completed, we're 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 a well.  We're more in a development mode here.  And, certainly, unloading fluids early in the well and things like that would affect some of that rate.

Harold Korell:  Yes, 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're 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 it's hard to pin down one single aspect to it, which is -- I know it's frustrating for you guys.  It's 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 in 12 or 13 different areas, and so we have the potential for variable results coming through the data, and it's due to a number of things.  It's due to the areas we're drilling in.  It's due 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'll be able to better understand what's going on.

Harold Korell: But when you're spread across 80 miles and 40 miles the other way, this is just the sum of all of it.  

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

Harold Korell: Well, I mean, we understand that.  And it's a good question and the book continues to be filled out.  And it's just--we don't have all the answers yet.

Tom Gardner: Well, thanks, guys.

Operator: And we'll move next to Scott Hanold with RBC Capital Markets.

Scott Hanold: Thanks.  Good morning.

Harold Korell: Good morning.

Scott Hanold: Could you guys talk a little bit about the average well 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 give us 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?

Richard Lane: Yes, 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 the little less controlled area in the far southern edge of the play and still learning some things there.  So--and not as much built-in practices in that new area that affected our costs.  We were using oil-based muds on a lot of those wells, which adds to the cost.  And we'll see if that's a practice that we're going to need to utilize long-term or if that's something we can get away from.  It depends on costs and programs and things like that.

We've had issues with well bore stability.  We've had well bore stability issues challenging things in the play throughout it, but maybe a little more so in the first quarter in those areas, which really just translate into a higher potential for hole problems.  And all of 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's some aches and pains going through that.  And not all those crews are operating at a level we would like them to and we're having to emphasis 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 affected well performance as well.

Scott Hanold: Okay.  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?

Richard Lane: Oh, I think our expectations will always be that.  Do they get--do they come to fruition quarter to quarter, it's a little hard to say.  But we're certainly going to drive towards that this year and I think our team will show that they can increase their efficiencies as the year goes on and that should help on the costs.

Scott Hanold: Okay, thank you.

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

Brian Singer: Thank you.  Good morning.

Harold Korell: Good morning.

Brian Singer: 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 in previous quarters.  I guess, how do we reconcile--how do we reconcile this?

Richard Lane: Well, I think we have a larger number of wells entering that set that are in some of the newer areas where we haven't 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 tweak 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.

Brian Singer: Was there any change in the timing of when you brought wells online versus your initial expectation?  And I guess, along those lines, could you comment on why your expectation is now in your guidance for a slight decline in production during 3Q and 4Q?

Richard Lane: I don't think there's a fundamental change.  The first part of your question, I don't think there's been a fundamental change in the 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 depending on how stepped out that location is.  But we don't--I don't think we see a big correlation between the number of days it's waiting and the performance.  So I wouldn't 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're pretty much on track with our number of wells completed.  So it's kind of good new/bad news.  Maybe there'll be a few less wells in Q3 and Q4.  But we actually completed at about the pace we would like to and 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 Q4 will be where the effect of a little bit lower first quarter wells will wash through the program and affect--maybe affect some of the production.

Brian Singer: Got it.  Thank you.  And then, lastly, does the East Cutthroat result at all change the rest of the profile for the Moorefield shale?  Or is it--or do you see it as unrelated?

Richard Lane: I see it as unrelated because we just don't know enough about the Moorefield shale.  We're getting into--starting 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're just--we're trying to point out for you where we've seen some variability and where we haven't, some statistical meaningful body of wells that we can say, okay, there's eight or nine horizontal wells.  I think there are nine now producing.  

And they are pointing to something that's less than what our typical average well is.  It's a pretty darned small area, but nevertheless, we're trying to point out some of the variability.  And when we have enough wells to pinpoint one area, we're trying to tell you about that.  I don't see it tied to the Moorefield and I don't see that we've got the answer there either.  There's a lot of things that we're trying to do there.  We did a lot of wells with--mostly all our wells there with crosslinked fluids with gels.  And our team is--everybody doesn't agree on what the cause and effect of all that is, but we do know we did mostly the wells with that.  And so, we obviously want to try some with slickwater and we want to push the laterals out there and see what results we get.

Brian Singer: Great.  Thank you very much.

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

Marshall Carver: Yes.  A couple of quick questions.  In the first quarter, if you completed the, say, number of wells that you were expecting, would you say it was well productivity that contributed to coming in above the high end of guidance there?

Richard Lane: Yes.  I would say--I would say that we basically--our average well is--and it's more than one quarter, really, Marshall.  If you think back about it, it's the wells we drilled in Q3 and Q4 of '06 that are really flowing through and providing that production boost.  It's a fast moving project and a lot of variables there.  But for the Fayetteville, I would say that the--that it's--more has to do with the wells drilled late last year than the ones in the first quarter of '06.  And then in--'07, sorry.  And then, in total as a company, we got--we had a nice boost from the conventional Arkoma.

Marshall Carver: Okay, that's helpful.  Thank you.  And then, on the longer laterals, would you expect the costs to be higher in Q2 compared to that $2.6 million cost for the more recent wells?  Should it be a little higher than that for the second quarter?

Richard Lane: Well, there's some benefits--there's some things affecting the costs upward and there's some things affecting it downward.  And I'm thinking that, with some of the improvements we're seeing, we're also negotiating the forward quarters on pricing for some of our--key services and things.  And we've gained some ground there, so I think that's helping.  I don't see them moving a lot from what we've reported here.  If we keep pushing out and adding more stages, then we could see that go up.  But we would have to see the well performance justify that.

Marshall Carver: Okay, thank you.  Good quarter.

Richard Lane: Thanks.

Harold Korell: Thanks.

Operator: We'll move next to Jeff Hayden, Pritchard Capital Partners.

Jeff Hayden: 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 are seeing any statistically significant differences with the slickwater versus the crosslinked gel, et cetera, et cetera.  And then, sort of a follow-on to that, people were testing all sorts of stuff in the Barnett Shale with dual laterals, simul fracs, things like that, and getting pretty good results.  Are you evaluating the use of that in the Fayetteville at all?

Richard Lane: Yes, Jeff, we are.  We're--I'm--personally, I'm very interested in the potential positive effects of what people are describing as simul 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 will that help well performance.  Several operators are talking about doing that and that that's helping them in these shale plays.  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 it's something we definitely want to pursue.  

And I think--when I think about the whole subject, the simultaneous fracing of a pair of wells has the chance--my hypothesis and I think some of our team's hypothesis is that below the ground from a performance standpoint it has a chance of creating a better overall network of fractures--enhanced fractures that should affect the overall production and drainage.

Jeff Hayden: Okay.  And on the completion techniques - the slickwater and crosslinked gel, see any differences there which are making you kind of lean toward one or the other?

Richard Lane: Well, there's--we're--there's some debate, really, even internally on that, what we think the best is.  We're working hard to try to sort that out.  Notionally, I would think the slickwater is the way to go.  There is some data that supports that.  When you build in some geographic bias like East Cutthroat was almost all crosslinked gels.  And are they--they're adding to the database that we're 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.  The other plays, it seems to be the completion technique that has risen up.  It doesn't mean that in our basin and our new play there's some inherently different things that could affect that.  But 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 helps--seems to help us overcome that.  But we don't have as clear an answer on that as we'd like, but that's my two cents of where I think it's heading.

Jeff Hayden: Okay.  And then, one last question.  It looks like the whale has become sort of 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?

Richard Lane: Well, the area that we--where the hump came from was the West Cutthroat area.  And I think the shaded area increased something like 30,000 to 40,000 acres based on that.  So, again, with 80-acre spacing, you can kind of--you can 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.  It was a Green Bay 1-21 well.  It's waiting on a 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 darned good well.  It's tested solid.  And so, we're trying to envelope that area in.

Jeff Hayden: Okay, guys.  Thanks a lot.

Operator: We'll move next to Jason Gammel with Prudential Equity Group.

Jason Gammel: Good morning, guys.  Thanks for taking the question.  I'm looking at the time to drill reentry to reentry going up by about two days in the quarter from 18 to 20.  But you are 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 a 15-day reentry to reentry goal still valid?

Richard Lane: Well, I think it depends on where we're--where we're drilling and what the true vertical depth is where we're operating.  And it's going to vary based on that quite a bit.

Harold Korell: For example, from the Scotland area, you're looking at 1,900-feet depths.  And down along that southern tier, 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're drilling, which is going to change across the board.  If we focused all of our drilling in the deeper part of it, we're going to be at a longer average time than we are if we're up in the--up in the--where the shale is shallower.  It's just a question of total days as well.  And then, the lateral lengths can extend the time out additionally.

Jason Gammel: 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 reentry to reentry target is still going to be valid over a longer term?

Harold Korell: Well, I don't know on the average, but that's our target right now.  That 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 or I could answer that.

Jason Gammel: 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 go-forward purposes, we should expect 2.6 million per well is a pretty reasonable run rate.  We should--and should we recognize that 1.4 Bs 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?

Harold Korell: Yes.  I would say that that--I mean, the way you described it there is accurate.

Jason Gammel: Okay.  Thank you, guys.

Operator: We'll take our next question from Richard Moorman, Capital One Southcoast.

Richard Moorman: 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 makeup of your drilling program right now.  First, Richard, you had talked previously about moving into new pad drilling in some areas.  I'm just curious if you can give a feel for how many of your wells are now being drilled on pads.

Richard Lane: You mean multi-well pads?

Richard Moorman: That's correct.  Yes, sorry.

Richard Lane: Yes.  There's--they're a very few percentage, Richard, of the total where that's happening right now.  We've done probably less than six wells that way, I would say.  And we're trying to--we're working on that.  We're 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're calling them "turnizontal" wells.  We not only have to get down there and build a curve later in the well, but we're actually having to push it out early and get away from the other well bore.  And we're 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.  And 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'll be some cost savings there.

Richard Moorman: Okay, super.

Richard Lane: And we'll keep--we're going to keep driving at that.  It's an important part to try to understand in our development scenario.

Richard Moorman: 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've 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?   

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

Harold Korell: But even having said that, often times it's not like we're drilling an 80-acre space well, we're drilling, in many cases--in most cases I think, we're drilling in new sections.  So, we're not as much drilling four wells in one section or eight wells in a section, as in a development program.  It depends on who you're talking to and how people think about it.  

But like in that East Cutthroat area, I think we have six wells there and each one of those was in a separate section of land.  So those were basically one well per 640.  So when you ask the question about multi-well paths and stuff like that, we're not at the place that they are in the Barnett where each individual little company has got X amount of acres and they're going crazy developing it like on 80 or 40-acre spacing.  We're still in a situation where we're spaced much broader than that.  

So when you step a mile away, even within a field, you certainly don't get the economies of a multi-path operation.  You may get variability that you otherwise wouldn't anticipate.  And I think that's an important thing.  I can't emphasize it enough.  We're drilling here across a very very broad area.  So we're still spaced out long distances apart.  

Richard Moorman: Super.  And still managing to beat everybody's guidance.  Last thought on the air drilling.  Just wondering, this is a technique that's been talked about in a lot of places.  East Texas has tried at Woodford.  I guess they're experimenting and even the Floyd shale's been commentary.  Just wondering what your thoughts are on the practical applications of air drilling in the Fayetteville?  

Harold Korell: Well, 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 Atokan 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 it into the Morrow shale.  And that's necessary just to keep the hole open, 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 we're in deeper than 5,000-foot depths, where we're doing some Morrow Basin mud systems just for hole stability, associated with the plays that you cut through in the rocks.  So I don't know if there's 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 hear us talking about that.  

Richard Moorman: Fair enough.  Thanks again and congratulations on a great quarter.  I look forward to the second.  Thank you.  

Operator: Nicolas Pope of JP Morgan.  

Nicolas Pope: 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 about the potential for commingling.  Can the same well bore be used for the Fayetteville and the conventional Arkoma, etc, costs?  

Richard Lane: Well, Nick, the conventional targets that we're encountering, it's pretty exciting and it's a good thing to be happening that we really didn't count on.  They are Atokan, Morrowan age type sands, which are not too dissimilar from what we've produced historically, back in the traditional part of the Basin, in what we call the Fairway, the big producing part.  So we're seeing some of those same 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 than I would have thought at this stage of the game.  So it's just nice upside for us.  

The commingling part of the question, basically what we're doing now is in that vertical part of the hole, like Harold was talking about, we're drilling that down on air pretty fast.  If we see a conventional target usually shows up in that part of the hole, then we usually get a really good look at it, because we are on air and we get a good sign that it's 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 could look at commingling.  We have zones behind pipe after we've completed a Fayetteville well.  

Nicolas Pope: Are you finding the prospects through drilling or is it through this additional 3D seismic data that you've gotten--that you've been getting?  

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

Nicolas Pope: Any idea what kind of area would be--is perspective at this point, to the conventional stuff on your Fayetteville acreage?  

Richard Lane: Not really.  Right now we've seen it in four or five pilot areas.  So, not really.  

Operator: John Gerdes of SunTrust Gerdes Group.  

John Gerdes: Richard, in those four pilot areas you just mentioned, the conventional work, what percentage of these wells in the vertical section are you actually seeing this perspective?  

Richard Lane: I don't know the total count.  We have more than the four good producers have seen some of the shallow zones.  Maybe they've been thinner in some other wells or not as good of shows.  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 eight or 10 wells, some sign of some more conventional zones present.  We just have the four producers on though right now, I think.  

John Gerdes: How many vertical wells in that area, 20 or 30 or so?  

Richard Lane: I don't know that exact number.  

John Gerdes: But you're not seeing it--.  

Richard Lane: We're not seeing it in every well.  Right.  And I wouldn't expect it to.  Even though we're in the Fairway, where we have a lot of well control, these can be fairly channelized facies and move around on you.  So we're not talking about big blanket sands.  

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

Richard Lane: Yes, they are.  They're shallow marine to Deltaic sands and if they're like they behave where we have more well control, they tend to be more dip oriented bodies.  Which means where we're drilling they're going to be North-South, plus or minus 30 or 40 degrees of depositional change there.  And they can be illusive to find.  They can be very narrow and you can think you're off setting a well north or south and it not be present.  But, we're pretty good at that, so if we get into an area that we can get our teeth into, we know how to chase it.  

John Gerdes: How's the decline profile look?  I know it's early days for volumes.  

Richard Lane: Yes, it's pretty early.  

John Gerdes: Really don't have much to add at this point, I guess?  

Richard Lane: No.  

John Gerdes: Okay.  You mentioned oil-based mud using some of these laterals.  And Harold had mentioned maybe in some of the deeper section of the Fayetteville you're working for formation reactivity.  What's the cost implications?  Are you picking up or using PDC bits in that situation?  Are you picking up p-rates, additional penetration rates?  How much more cost are we looking at there?  

Richard Lane: I think the cost of the mud, when we go to oil-based mud I think we're probably somewhere in the $200,000 to $300,000 cost range.  

John Gerdes: Incremental cost?  

Richard Lane: Right.  And what happens is, you know, pay me now or pay me later or maybe we have a little bit more up-front deciding we're going to be oil-based, to get the stuff out there we need for that, pay for the incremental chemicals and all that kind of stuff.  And then basically you see more stable well bore, less problematic well bores, easier to clean horizontals.  And so the cost savings is a little hard to pin down, but lowering the trouble costs.  

And then we're looking at some other technology too.  We're just starting to scratch the surface on looking at drilling with casing and seeing if that's a technology that we could bring to bear on the play, and some other things.  

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

Richard Lane: Most of the time we're running liners.  

John Gerdes: Shifting gears on your stimulation.  What kind of sand loading are you doing for stimulation and how many stages have you kind of migrated to?  Are you doing three per these laterals of a little over 2,100 feet or is it four?  

Richard Lane: We've been in the 4 to 5, probably more likely we've been at the 5 stages, has been kind of our norm.  And we're putting about 1 million pounds of sand away in those stages.  

John Gerdes: In aggregate, right?  

Richard Lane: Correct.  

John Gerdes: And the cost per stay, what are those costs running you per stage?  

Richard Lane: They're about, it depends exactly what we're doing, $200,000 to $250,000.  

Operator: Christopher George of Capital One Southcoast.  

Christopher George: Just a couple of quick housekeeping items.  Can I get the production per area?  I've got the Fayetteville shale 8.2 for the quarter and East Texas at 7.6.  I just want to confirm that.  And then I wanted to hit Arkoma and the Permian Basin as well.  

Richard Lane: Yes, Chris, you've got those two right.  And then the Arkoma would be 5.5 Bcf for the quarter.  Gulf Coast 0.4.   Permian Basin 1.2.  

Christopher George: And did I catch you right saying you run five rigs in Arkoma?  

Richard Lane: That's correct.  

Christopher George: And then I'll throw you a curveball real quick with Angelina River Trend.  I just want to get some results there and see how things are going.  

Richard Lane: Not a lot of wells to report on yet there for the first year.  What we're kind of looking for, I think our model well would be about a 1.4-1.5 Bcf well, Travis Peak well and testing somewhere 2 to 2.5 million a day type, if you look historically at what we've done.  And we're getting started on that Jebel block, which is an exciting block, a pretty nice new acreage block we have there.  

Christopher George: You gave a gross acreage.  What's your net there?  

Richard Lane: I'm not exactly sure of what that number is.  

Operator: Gil Yang of Citigroup.  

Gil Yang: I just wanted to go back to this issue of--I think Harold, you've already said a couple of times you didn't know, but the 68 wells, any idea of the proportion in the new area versus the old areas?  

Harold Korell: I think we're probably greater than 50%, Gil, in the first quarter in the new areas.  

Gil Yang: Okay.  For the wells that you were drilling in the old areas, are you still comfortable that costs are in the $2.2-$2.3 million range?  Those costs have not gone up.  It's more the new wells that have gone up in cost, is that fair?  

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

Gil Yang: Right.  Okay.  In the case of the newer areas, obviously well costs are higher because you're sort of doing more experimentation, if you will, poking around and figuring out what's best.  Would you say that at the same stage of development for these older areas were the well costs similar, given that inflation has gone up as well?  But are you seeing the same sort of learning curve costs in these newer areas or on other areas or are you experiencing more learning curve costs in these new areas than before?  

Richard Lane: 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'd caveat that with qualitatively both of them moving with inflation.  I would say yes, it's a similar type situation.  

And then as we add laterals to it, maybe that's the incrementally different piece.  

Harold Korell: I think we need to be clear that it's just not newer versus older, it has to do with the depth we're drilling at, shallow versus deeper.  Where the shale is deeper it's going to be more expensive.  So if in your mind in your question you're combining newer areas with deeper areas, you'd be fooled by newer versus older, because it's deeper versus shallower.  

When you consider that we're drilling some wells that are--listen to what I'm saying--1,900 feet deep, we're drilling some that are 5,000 to 5,500-feet deep, that's twice as deep.  It also is pushing, if you'll think about it, it's pushing as we've moved to the south and east, we're pushing towards the area in which Chesapeake's wells have been and that they've had higher costs and using oil-based mud.  So you've got to think about what you're physically doing here.  

Gil Yang: Are you getting to the deepest portions of your acreage or is there still stuff that's deeper?  

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

Gil Yang: Okay.  And do you have any indications yet whether or not the recoveries will be higher at those deeper depths?  

Harold Korell: We don't have a conclusion on that.  

Gil Yang: Based on the data you're seeing so far, can you make some preliminary comments?  

Harold Korell: I can't.  Richard, maybe you want to venture something like that?  

Richard Lane: The depth relationship all to itself, if you just--that East Cutthroat is in one of the deeper areas and that performance right there is not what we'd like it to be.  Will it ultimately get better?  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 help.  Now that's not talking about costs or economics, it's just talking about packing gas in place.  

Gil Yang: I'm sorry, did you say what Cutthroat produced at, what the recoveries seemed to be versus the other areas?  

Richard Lane: No, we didn't talk about the recoveries.  The average well there is less than what we've seen in other areas.  

Gil Yang: Are they still big enough to be economic or not?  

Richard Lane: I would say we're 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're not getting it in that little small area right there for sure.  But that's why we want to try some slick water completions and we want to try some [watery] laterals.  What I wouldn't infer is that the deeper is worse in any kind of a global--.  

Harold Korell: Or that it's better.  Just what I said in the beginning is that I don't think we can say because it's deeper it's better, we'll have better performance or worse performance.  It's probably going to wind up being related to fracs or stimulation effectiveness and the rock type that's there, the rock that's there.  And the thickness that's there.  You've got all of these different moving parts across an 80-mile wide area and the shale is not the same thickness across it.  If we had the answers, Gil, we'd just give them to you.  

In other words, there's a lot of variables and we don't have a complete conclusion on it.  But we darn sure know that the East Cutthroat area is not as good as some of the other areas.  And that 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're 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.  The point is for what we're seeing right now, the East Cutthroat is not looking at that little area is about 4,000 acres isn't looking too good to us.  

I think our East Cutthroat, we drilled about six wells on a mile apart each.  So, we've got more assessment to do.  

Gil Yang: Okay.  Last question at the moment is that it sounds like the 300 million is still on track for the end of the year for exit rate?  

Richard Lane: Yes.  We're not really changing that.  It's 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're still driving towards that.

Gil Yang: Okay, Richard, as there's some discussion about the decline curve earlier with lower IPs, but it's certainly a shallow decline rate versus the type curve.  From your perspective, the hitting, whatever target or whatever goal you have, are you helped or hurt by the – are you helped or hurt net between the, the, the positive of the lower, slower decline rate with the negative of the lower IP?

Richard Lane:  Well, it depends on what you’re talking about.  If you’re talking about near-term production?

Gil Yang:  I’m talking about getting to that 300 exit rate?

Richard Lane:  Well, near-term production you’d rather have a higher rate.  In terms of estimated ultimate recoveries and things, maybe you would conclude something differently, but we really have to be careful with those, with those curves we put out there.  And the way we do our work is by assessing every single well on to itself.  It’s just a compilation of all that, all those wells, put in one place.

Harold Korell:  Gil, I, I – let me say this about 300 million exit rate, that’s not our – I mean let’s not get tangled up about what our objective is here or our target.  I – we have tried to give people a guidance, so as to where we think we could be on this thing by yearend, and that’s the 300 million a day.  

You know, there’s a lot of other objectives and targets out here. And the main target is to figure this all out and do it right, and do the right things, and achieve the PVIs that we want to achieve, and so, you know, that’s what’s still going to guide our activity.  You know, we’re not going to do everything we can to get the 300 million a day, at least that’s not my objective for it.  And, but you call it a target, maybe it’s just a terminology, but, you know, that’s just a guidance as to where we think we have a good chance of reaching that, but there’ll be a lot of things in between here and 300 million a day that are going to occur.

Gil Yang:  Okay.  Fair enough, Harold.  Appreciate the comment.

Operator:  We’ll move next to Michael Scialla with A.G. Edwards.

Michael Scialla:  Hi, guys.  On your 181 wells that go into that composite curve, can you tell us what percentage of those have been drilled with laterals, say, longer than 2,500 feet at this point?

Richard Lane:  Mike, it would be a very, very small percent.  I don’t have that exact number, but –

Michael Scialla:  Less than 20?

Richard Lane:  Oh, yeah, yeah.

Michael Scialla:  Okay.  And then kind of along those same lines, if you are trending toward longer laterals, if that bears out to, if that works out, is it safe to say that the 400 squares of 3Ds that you’re planning are going to be key to going for longer laterals, or I’m trying to get a sense do you, do you need the 3Ds to be more confident in drilling the longer laterals or is the 3D a necessity in just certain parts of the play, given the complexity of, of various areas?

Richard Lane:  Well, I think it’s going to be, no doubt in my mind it’s going to be a beneficial tool towards more efficiently drilling longer laterals and having less, you know, getting out there part way and getting lost or leaving your target or encountering something that you couldn’t anticipate.  So I think it’s definitely going to be a better, it’ going to be an improvement tool that will allow us to do better at that, no question about that.  

And then, you know, where we’re doing them, I don’t think we have to stop.  We’re not going to wholesale 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’ll have to maybe use some pilot holes in areas that we, that we don’t yet, but, you know, it doesn’t mean we’re going to wait before we get all the data to start that, but it definitely will be a good tool to help us.  

Michael Scialla:  Is it likely you’ll go beyond the, the 400 squares?  It’s – thinking about now?

Richard Lane:  Well, we just, we’ll just have to see.  You know, I don’t want to guess what that’s going to be right now, but if it turns out to be an economic tool, that’s the key.  You know, 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.

Michael Scialla:  I guess along those lines, too, the $2.6 million for the wells drilled this quarter or the first quarter, I assume that doesn’t have any allocated seismic built into it?

Richard Lane:  That’s correct.

Michael Scialla:  Okay.  Thank you.  That’s all I had.

Operator:  We’ll go to Philip Franz, Buckingham Research.  Hello, Mr. Franz.

Bob Christensen:  This is Bob Christensen speaking, at Buckingham.  This 3D seismic –

Harold Korell:  Bob, can you speak – we have trouble hearing you here?

Bob Christensen:  Yes, Harold, can you hear me?

Harold Korell:  Yes.

Bob Christensen:  The 3D seismic, sorry, is it, is the resolution, I guess is the word, set for the Fayetteville or will it illuminate to depth, you know, 15, 16, 17,000 feet down?

Richard Lane:  No, it’s, it is – the design of the acquisition parameters are not setting around imaging that deep, Bob.  

Bob Christensen:  Okay.

Richard Lane:  They’re – I would say it’s fair to say they’re more centered around the Fayetteville, but what’s that going to do is it’s going to give you a high quality data from the surface, near surface down to the Fayetteville, and it’s going to give you some high quality data below the Fayetteville where there’s some other targets, but not, you know, it’s not shocked, to image is super deep.

Bob Christensen:  So is Arbuckle data excluded?

Richard Lane:  Well, I would say, I would say nothing has been excluded.  There’s a lot of targets that, that actually come into our field of view with that data, so I wouldn’t say we’re excluding anything.

Bob Christensen:  As I remember, you know, from the Fayetteville Geologic Society, the Arkansas Geologic Society, they had some dots on the map, so about to the east of Arbuckle tests, you know, done in the ‘70s, and I think they were dry holes, largely.  But would that be a possibility for you guys down the road?

Richard Lane:  Well, I would -- it’s, it’s always a possibility.  I wouldn’t say it’s way up there on our priorities.

Bob Christensen:  No.

Richard Lane:  We have some, we have the conventional sands, shallower, and then we have some, some deeper carbonates, but not a lot deeper, that are, you know, certainly exploratory but not as, not as great an unknown as say the Arbuckle might be.  And then there’s places where the Arbuckle wouldn’t be as deep as those other areas that you commented on, but.

Bob Christensen:  Okay.  Well, great.  Thank you very much.

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

Harold Korell:  Well, thank you for being with us today.  I know it’s a busy time for everyone, so we’re going to wrap this up, and see you next quarter.

Operator:  That does conclude today’s conference.  You may now disconnect your lines, and thank you for participating.