西南能源 (SWN) 2007 Q3 法說會逐字稿

Good day, everyone, and welcome to the Southwestern Energy Company Third Quarter Earnings Teleconference. Today's call is being recorded. 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. Thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of the press release we announced yesterday regarding our third quarter results, please call 281-618-4784 to have a copy faxed to you. Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements section of our annual and quarterly filings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

In preparing for this teleconference today, I couldn't help but reflect on the changes in our company over the past few years. Nearly ten years ago, we set out on a new strategy for our company. That was to build an organization capable of generating high return drilling opportunities. We have with the help of a lot of good people been highly successful with this, evidenced by our developments at the Ranger Anticline in Arkansas, our East Texas activities at Overton, and, in a bigger way even, our large acreage position in the Fayetteville Shale.

In our E&P business, the third quarter brought further positive developments in our key operating areas. Our drilling activities in the conventional Arkoma program at the Ranger Anticline and at Midway are going extremely well. Our production will grow there this year. Finally, we are continuing to push the ball down the field in the Fayetteville Shale Play with longer horizontal wells, larger fracs and with the benefit of our growing 3-D seismic knowledge.

In the Fayetteville we're building the database of production history on our wells and we're continuing to drill in new areas to evaluate our very large acreage position. As we reported in our press release yesterday, we are experiencing better performance with longer laterals and larger frac stimulation treatments, which we expect will result in higher EURs for these wells.

I would like to now turn the teleconference over to Richard for more details on our E&P activities and then to Greg for an update on our financial results.

Thank you, Harold. Good morning. During the third quarter, our natural gas and crude oil production totaled 30 Bcfe, up 56% from the 19.3 Bcfe we produced in the third quarter of 2006. The increase was primarily due to growth from our Fayetteville Shale Play, which produced 14.7 in the third quarter of 2007 compared to 10.7 in the second quarter of 2007 and 3.8 in the third quarter of 2006.

Due to our strong performance in the third quarter, we expect our full year's production to be approximately 111 Bcfe above the top of our previous guidance range of 107 to 110, and we expect our Fayetteville Shale production for the full year to be approximately 51 Bcf.

In the first nine months of 2007, we invested approximately $1.05 billion in our exploration and production activities and participated in drilling 476 wells. Of those, 287 were productive, 10 were dry and 179 were in progress at September 30 for an overall success rate of 97%. Of the $1.05 billion invested, approximately $872 million or 83% was for drilling wells. We currently have 31 rigs running in the company, fifteen deep and four shallow rigs in the Fayetteville Shale Play, six rigs in East Texas, one in North Louisiana, one in the Permian Basin and four in our conventional Arkoma Basin activities.

At the Fayetteville Shale Play during the first nine months of the year, we have invested approximately $731 million and have placed 187 wells on production. Gross production from our operated wells has increased from approximately 100 million cubic feet per day at the beginning of 2007 to 260 million cubic feet per day at October 22. Approximately 16 million cubic feet per day of our current production is from eight wells producing from conventional reservoirs, and they're spread out over six different pilot areas in four counties. And we expect to be producing approximately 300 million cubic feet per day gross from our operated wells at the end of the year in the Play.

During the third quarter our time drilled to total depth averaged 16 days from reentry to reentry compared to a second quarter time of 18 days. Average completed well costs during the third quarter were $3.0 million per well, slightly higher than the $2.9 last quarter, that we completed in the last quarter. That's due to drilling and completing wells with longer horizontals and some larger fracture stimulations.

Although our average total well costs for the quarter was up, we have reduced our drilling and completion cost on a dollar per foot basis quarter on quarter. Lateral lengths for the third quarter averaged 2,613 feet compared to 2,497 feet in the second quarter. In the third quarter, we began to see improved performance due to shifting the focus of our drilling activities to areas that have been identified as better performing to date and were possible where we have 3-D data.

As of September 30, we have acquired a total of approximately 320 square miles of 3-D in the Play and expect to have approximately 450 square miles of 3-D seismic acquired by year-end. We completed nearly all of our third quarter wells using slickwater stimulation, and approximately 20% of the completion used open-hole packer systems. Now, these wells have confirmed our analysis that indicated that both the slickwater and open-hole packer systems yield better performing wells.

We are also seeing better well results and growing longer horizontal laterals. To date, we have drilled and completed 24 slickwater wells with lateral lengths over 3,000 feet. In our press release, we provide an updated normalized average daily production for horizontal wells. In addition, we have provided a normalized average curve for the 24 wells with longer laterals. Based on our analysis and forecast, we expect average gross estimated ultimate recovery from wells with greater than 3,000 foot laterals to range from 2 to 2.5 Bcfe per well.

Approximately 26 million cubic feet per day of our current production is from three of the company's eastern most pilot areas located in White County. Production increases in these three pilot areas alone account for approximately 28% of the 60 million cubic feet per day increase in gross operated production since the end of July. Within the last 35 days, we have placed two really good well-time production, with production rates over 5 million cubic feet per day. The pool, 115 in our Sharkey pilot area, is fracture stimulated using a slickwater fluid system along 2,949 feet of horizontal lateral section and was placed on production at a rate of 5.2 million cubic feet per day. And the Featherstone 122 well, also in Sharkey, fracture stimulated along an open-hole factor and slickwater system 2,946 feet of lateral length and that was placed on production at a rate of 5.4 million cubic feet per day.

We plan to invest approximately $1 billion in the Fayetteville Shale project area during 2007, including our investments related to the gathering system. This capital investment includes participating in approximately 400 horizontal wells in the Play, of which approximately 70% are expected to be operated by us.

We also began investment in a demo project that we have near Southeast Rainbow in the third quarter, and that project is designed to test longer laterals, concentrated well activity, multi-pad drilling and some efficiencies we can gain from our operations. And we'll report more on that as that unfolds in the fourth quarter and next year.

In our Arkoma Basin conventional projects, we continue to have very positive results here, as Harold mentioned. We have invested approximately $126 million here drilling 85 wells of which 65 were productive and 15 were still in progress at the end of the quarter. We're continuing to put good wells on production at our Ranger Anticline and our Midway fields. And as a result, production from those properties in the basin was 6.3 Bcf for the quarter, up 26% from the third quarter of 2006.

In East Texas, we continued our active drilling programs with three rigs at Overton and three rigs in our other project areas. In the first nine months of 2007, we invested approximately $150 million drilling 35 wells at Overton and 21 wells in our Angelina River Trend, four wells in our Jevelle prospect and four in other areas. All of these wells were either productive or in progress at the end of the quarter.

Production from East Texas was 7.6 Bcfe in the third quarter compared to 8.2 last year. To date we have now spotted five wells on our Jevelle acreage block in Shelby County, Texas. Three of these wells are drilled through the Travis Peak formation and two are horizontal wells farrging the James Lime horizon. Of the three Travis Peak wells, one is currently on production and two are testing. Both of the James Lime wells offset some notable activity by other operators. Cabot Oil & Gas announced last week the Timber Star Orshon well had been completed in the James Lime and was flowing to sales at a rate of 12.2 million cubic feet equivalent per day.

We hold a 21.5 % working interest in that well, and the Timber Star Mills No. 1, which we operate with a 100% working interest is drilling, and we expect to reach total depth during the fourth quarter. And pending results at both the Travis Peak and the James Lime wells, there may be significant growing potential for this area in 2008 and beyond.

On the new ventures front, we are continuing to identify and pursue additional unconventional opportunities to add value. Yesterday we announced that we had leased approximately 70,000 net acres in Pennsylvania over the last year that we believe is prospective in the Devonian Aged Marcellus Shale. We plan to drill our first test well in this exciting new Play in early 2008.

In summary, we continue to be very encouraged by our success in our Fayetteville Shale project. It is advancing very well and holds tremendous potential to continue to organically increase our production and reserves at very meaningful rates. Our East Texas and conventional Arkoma Basin areas are also performing well as we continue to identify additional opportunities to add value there.

I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Richard. Good morning. Our earnings for the third quarter were $51 million or $.30 a share, up 52% from the prior year. Our record financial results were driven primarily by the positive effect on our earnings of our significant growth and production volumes from the Fayetteville Shale Play and higher realized natural gas prices, which were primarily the result of the positive effects of our hedging program.

Net cash provided by operating activities before changes in operating assets and liabilities increased 66% from the prior year to $157.7 million. We produced a record 30 Bcf in the third quarter and realized an average gas price of $6.66 in Mcf, which was up $.43 from the prior year. Our commodity-hedging program increased our average gas price during the quarter by $1.17 per Mcf. Our current hedge position, which consists of six [bright] swaps and collars, provides us with support for a strong-leveled cash flow.

For the remainder of the year, we have approximately 70% to 75% of our projected natural gas production hedged. We have 11.5 Bcf hedge with fixed price swaps at an average price of $8.09, and we have 10.5 Bcf hedge through price collars with an average floor price of $7.10 and an average ceiling price of $11.21.

We also have hedged 97 Bcf in 2008 and 72 Bcf in 2009 at attractive prices. Our detailed hedge position will be included in our form 10Q. Our lease operating expenses per unit of production were $.67 per Mcf during the third quarter, down slightly from last year but almost down $.15 lower than our previous guidance. Our LOE was lower than we expected due in part to a decrease in cost of fuel gas for compression-related expenses, partially offset by increase in our gathering cost, both primarily related to our operations in the Fayetteville Shale Play.

General and administrative expenses per unit of production were $.46 in Mcf in the third quarter, down from $.54 in the prior year. The decrease was primarily due to increased production volume.

Taxes other than income taxes per unit of production were $.11 for Mcf during the third quarter, down from $.32 in the prior year due to a change in the mix of our production. Our full cost through amortization rate was $2.56 per Mcf in the third quarter. Our midstream services segment has installed over 230 miles of gathering system during the first nine months of the year and is currently gathering over 300 million cubic feet of gas per day from the Fayetteville Shale Play.

Operating income for the segment was $4.1 million in the third quarter, up from $1.3 million in the same period a year ago; and the increase was primarily due to increased gas gathering revenues related to the Fayetteville Shale Play. Our natural gas distribution business realized a seasonal operating loss of $3.5 million in the third quarter compared to a loss of $4.5 million during the same period last year.

At September 30, we had total indebtedness of approximately $732 million, which included $594 million borrowed on our revolving credit facility, resulting in a capital structure of 31% debt and 69% equity. On October 12, we amended our unsecured revolving credit facility and increased the borrowing capacity to $1 billion. This amount can be increased to $1.25 billion at any time upon our agreement with our existing banks or additional lenders.

We plan to fund the remainder of our 2007 capital program with cash flow and debt borrowings and expect our long-term-debt-to-total-capitalization ratio to be approximately 36% at year-end. That concludes my comments, and I will turn back to the operators who will explain the procedure for asking questions.

Thank you, sir. [Operator Instructions] And we will go first to Jeff Hayden at Pritchard Capital Partners.

Hey, guys. Congratulations on the great quarter.

Thank you.

Real quick, just looking at some of those tests you guys put up in White County on the Sharkey pilot. I think before this, the biggest well that you guys have had out in White County was on the full pilot; I think that was the Reaper 112. Can you give us some sense of the distance between that and some of these wells on the Sharkey pilot, and then how many rigs you guys have running in White County right now?

Well, I don't know the exact distance of that. It's not too far. I'd say it's probably five to ten miles north of the Reaper where these Sharkey wells that we've reported on. So basically they are both eastern most pilot areas, if you will, and the Sharkey wells would be a little bit north of that Reaper well. And I'm not sure of the exact rig count. I think we have two or three of our rigs active over in that eastern area right now.

Okay. Thanks a lot, guys.

And we'll go next to Robert Christiansen at Buckingham Research.

Good morning.

Good morning.

Question on the capital spend in the quarter. It was up about 30% sequentially. Is there any explanation for the real run-up in capital spending, just high levels of activity or what am I missing here?

Rob, this is Greg.

Thank you.

You know the CapEx, as we said in our press release, we're looking at we're probably about a $100, $110 million above our earlier projections for the full year and that obviously is a run right in our increase. Completion links some of that hit in the third quarter and the fourth quarter will be -- fill that gap. That basically is about $98 million of increase over the original projection to where the totally in fee dollars invested this year we expect to be about $1.3 billion. And then in the midstream side, we'll be up to about $100 million versus about $84, $85 million originally projected there, just due to increased pipe we're putting in the ground and with increased activity.

Okay. Great. And a follow on. Regarding taxes, you said they're down to $0.11 an Mcf from $.32 last year. I know you've mentioned that's because of production mix. I wondered if you could elaborate on that a little bit, and do you expect it to stay there going forward?

Well, we had a couple of different things that helped us there. In the third quarter, we also had -- in fact, for the nine months year-to-date, we've had over $3 million of tax credits received from the State of Texas due to some changes in the law there. There was a cap, a $1 million cap on refunds. And so those are -- there's a big chunk of that that really related to 2006. So, we have kind of a windfall that's really helped our rate drive down and then just changing mix of our production.

Thank you. We'll get in back of the line.

And we'll go next to Tom Gardner at Simmons & Company.

Good morning, guys.

Good morning.

Good morning.

Just with respect to the 24 longer lateral wells, have those been drilled and sort of been a widely distributed pattern or has it been concentrated in just various areas?

It's pretty widespread. I think there's 10 different pilot areas that account for those 24 wells. So, it's across the Play pretty much.

Moving over to the Marcellus Shale, I just wanted to kind of get an idea of the competitive landscape and what might be your focus areas there. I have several questions along those lines, but I'll just let you tell me what you're going to tell me. And then is your planned well next year likely to be horizontal or vertical?

Well, I would say I probably won't tell you much more than what's in that press release for some obvious reasons, competitive reasons. And we're active there. I think we'll start out with vertical pilot wells to gather data and then -- and likely move to some horizontal drilling.

I'll jump back in line.

And we go next to Joe Allman at J.P. Morgan.

Hi. Good morning, everybody.

Hi, Joe.

Hi. In terms of the drilling the 3,000 plus foot laterals, over what acreage -- and I know Richard just said that the 24 wells are across the Play. But over what acreage do you think you will be drilling this kind of, besides laterals? And, where -- could you talk about maybe what percentage of the acreage do you think this kind of drilling would apply to? And also what kind of spacing would you be thinking about you might ultimately get to in this Play?

Well, I think the acreage or the area where we would drill them -- what we're seeing there, Joe, is that maybe we have better well there, that we can have higher EURs in. That would be -- give us better economics so we would -- if that holds true, we would try to buy us all the acreage we can. We don't see any kind of geographic bias for that. So, we would try to approach the Play as we have from the start. We're trying to improve the well results in how we're doing them and I think it applies to the whole acreage.

Obviously we have some acreage that we've developed already and some spacing determents made there. But, I think it applies for the whole Play.

And maybe just to add a little bit to that, Richard. If you think about the build-up scenario that we've been in over time here, that you move all the way back to two years ago or when we just were starting drilling and started drilling horizontal wells across a very broad area where we didn't have any data yet, the obvious thing for us to do -- and we've talked about this over these teleconferences over the past couple of years -- when we were moving into new areas, we would generally drill a pilot hole and then a couple thousand foot lateral because it didn't make a lot of sense to risk trying to drill longer laterals when we were doing assessment drilling in new areas to find out how productive it would even be. And we have said that as time would move along, we would -- we will begin to drill some longer laterals.

There are interesting developments that generally take place as you think about the geometry of the wells that we're drilling. And it's a lot of detail to try to paint a word picture for you over the phone. But, generally, our -- the orientation, the direction of our horizontals has been in the northwesterly direction. And, units are spaced here on government section and so that would allow you when you went in the first well in a section, you might generally drill a shorter lateral because you're drilling in one of the corners and then later you would think in terms of drilling the longer laterals.

Now in this -- what Richard mentioned earlier, this -- what we're calling internally here a demo project in Southeast Rainbow, we're taking basically a four-section part of our acreage, four government sections and we're going to be using a slightly different orientation to our wells.

We're going to be drilling -- he mentioned drilling multiple wells off a single pad. We will be drilling wells in a north-south orientation. If you think about one square mile and think about putting the surface location along, say the northern border of a one square mile and then drilling wells both north and south off of that with an attempt to drill as long as laterals as possible, spacing them approximately for this test, the well bore is approximately 1,000 feet apart, parallel to each other across that section, and then ultimately having an east-westerly well that would pick up reserves that otherwise wouldn't be drained along the northern section line.

So your question about spacing, we don't know the ultimate development spacing here. We've talked at times about 80-acre spacing, which would mean 8 wells per section, thinking in terms of variable lateral lengths under the scenario of drilling wells in a north- westerly direction.

However, if you begin to do a geometry of drilling wells in north-south off of pad and then picking up what wouldn't be drained during the turn part of the well, that you would drill in an east-westerly direction along the northern boundary, then in 1,000 feet apart, you could think of it if you keep sequencing that across sections that you would have maybe 6 wells per section, but they would have longer laterals.

And with an assumption of 500-foot radius on fracturing, then you might be able to recover all those reserves. So we don't know if that's the absolute answer, but we're going in with that kind of a test and we'll see what it shows us. And we're beginning that activity now. Locations are built for drilling wells and that will all unfold now over the next basically six to eight to ten months a year because it will take us that time to get all this done.

The other things we'll be able to see in doing that are what are our costs going to be when we get concentrated on development. And by the way we haven't been concentrating on development; we still got acreage to assess. So, there's going to be a lot more interesting information come out. It might tell us that that 1,000 foot spacing between horizontals is too far and it might mean that ultimately a lot tighter spacing.

It's a big project. We have a lot of work to do, but we think we're approaching it the right way with this particular test.

I have a pretty good work picture now, and I appreciate that. In terms of shallowed conventional, could you talk to -- at that place as you've (inaudible) pretty well. Could you talk about how extensive that Play might be? And is that formation is that - do you think it might be continuous across a lot of your acreage position?

Well, Joe, the general packages are continuous across the acreage. The individual sands that we're finding are -- there's for sure a strata graphic component to them and they'll be variable across the acreage.

I think the really good thing is that we've seen (inaudible) sand production pretty much across the whole Play, and so we know it's not isolated to just one little part of our acreage there. And the other thing is that we've seen some really nice rates from those wells, at times unstimulated rates, that are 3 and 4 million cubic feet per day.

So the jury is still out on how extensive it's going to be. The things that are pointing in a good direction is that we've found it over a pretty broad area and we're, we're just now really working that harder. I think 3-D seismic will be a nice benefit for us there and we're hopeful to find some sizable accumulations there.

The good news about it is we get to look at it as we're drilling wells down to the Fayetteville. And so if we find it, we can stop and complete it. The other beauty of it is that they're fairly inexpensive. And it's like $600,000 or $700,000 a well, and they also help us earn acreage as we do those.

And so to the extent we can begin to map those -- which we have an effort underway to map those -- those can be very helpful in a number of ways in earning acreage as well as in providing some very nice cash flow. That is -- that's a good thing.

I appreciate that. Thanks, guys.

(OPERATOR INSTRUCTIONS) And we will go next to Amir Arif with Friedman, Billings, Ramsey

Good morning, guys. Congratulations on a great quarter. Richard, I know you just said you don't have much to say right now of the Marcellus Shale, but could you give us a sense of how many wells you're looking to drill in the first half?

Amir, no, I don't really have a lot more to share with you there. It's going to really depend on the testing that we do in some of these first wells and in gathering the real core data there for rock properties and all that and that will really determine those levels of activity.

Hopefully, you did find and start drilling some wells. And is it Q1, '08 or are we just talking sometime early '08.

Yes. I think we'll start permitting here before the end of the year and hopefully get them going early in '08. We've got some weather issues there to deal with as well.

Okay. And second question. Can you just update us on how you're progressing on your takeaway capacity?

Yes. Amir, this is Greg. Things are going really well there. As far as the Boardwalk Pipeline, they submitted their (inaudible) application. They have over a half of their right of way purchased. They've actually got - have some delivery of pipe that's currently been coded so we're real pleased that's right on schedule where our anticipation was this time.

We also - I'll just remind you there's the two other lines in -- and the Ozark line has the capacity of 330 million a day. We hold about 225 million affirm on that line. And then (Centerpoints) line that runs along the south. The Play has a capacity of about 250 million. That, the firm on that is already subscribed to, but we can move gas to the ultimate end users on that also.

If there are any Boardwalk listeners on the line, you guys keep the pressure on that project.

Sounds good. Thanks.

And we will go next to Brian Singer at Goldman Sachs.

Thank you. Good morning.

Good morning.

Can you talk to where you think your, your drilling completion costs would be at 3,000 foot lateral wells at Fayetteville? And then, where do you feel you are in terms of the maturity of that drilling and completion cost, i.e., to what extent is there room for that to come down?

Yes, Brian, well I could tell you probably a good tanker number there is the 24 wells that we've talked about that were greater than 3,000 feet that make up that production set. I think their average was $3.3 million per well, and we have a little more than half, probably 55%, 60% as completion.

In terms of where we are on the maturity of drilling cost and gaining efficiencies, I think a lot of that has to do with -- or is controlled by what Harold talked about earlier. We really are not in the development phase yet. This demo project will start to do that. But, because we are stepping out into a lot of new areas and have a lot of diverse conditions that we're having to deal with there, we're really not in the factory mode yet so we're not seeing -- although we're seeing some efficiencies quarter-on-quarter like we reported, we're not really in that hardcore development mode where we would expect that we would drive those costs down.

I can't tell you how much they'll come down. I will say that in other projects where we define the development mode, we've been able to do very well to drive those costs down.

And in terms of spending, how do you think about that and how do you balance that going forward? And how do you think about your financing options and balance sheet flexibility?

Well, the first thing is we don't use the term spending. Brian, we use - we always call it investing. And I've said around here that we mash people's thumbs when they say it's spending. I know it's a word people use but we think about it as investing. But, Greg, I'll let you answer the question about that otherwise.

Luckily I'm not in the room.

Yes, we have a grin on our face all of us because of -- that's been an internal joke or whatever for years, but we think we're very well positioned, Brian, right now. We talked about and we've given our guidance and about where we are.

As far as the year, we were going to be clearly a user of our debt capacity this year and that's worked out. Our cash flow is running higher than our projections were as gas prices have been a little better ahead. This is looking a bit better for us. And our - but our -- and our CapEx is up a little bit but will be about exactly kind of where we projected the beginning of the year.

I mean, as we -- we haven't built our plan for 2008. Right now it's in the process. We were looking very hard at that obviously and -- but we still -- and even though our cash flow, as production has grown over 50% this year and we'll have in the year overall strong number and obviously have some strong numbers in 2008, we wouldn't anticipate our cash flow quite equals our CapEx run. So, we'll still be incurring some levels of that but still within a very reasonable capital structure.

Great. Thank you for investing the time to answer the question.

And we'll go next to Scott Hanold at RBC Capital Markets.

Thanks. Good morning.

Good morning.

Hi. You guys obviously in the past have talked about doing different things as far as during inflation and it sounds like you're doing a demo where you do some pad drillings. Can you sort of talk about any efforts in trying the simulfrac or have you tried that or do you expect to here over the next quarter?

Yes. We've had limited experiments with that. We've -- actually what we've done there is, it's just a few wells and we really haven't. It depends on what you call a simulfrac. We've done kind of two wells back to back but maybe not alternated the stages. So, we were actually doing two wells at the same time and alternating the stages. There's been some of that work done in the industry and that's very interesting. And so, we have some more of that to do. We don't really have much conclusive results to report on that, but we probably will continue to experiment with that.

I think one of the constraints on us doing that is we haven't drilled a large number of wells that are like sitting side by side because -- and again, that's because we're not down to that sort of spacing generally across the Play because we still have our drilling rigs relatively more spread out.

That's an open field I guess on that and I know there's been discussion internally. Then, in the demo project that would afford us really our first opportunity to be able to gather that type of data in our area.

We have to mass a lot of water in one place to really do that effectively, and that's part of what we can do on this in the more of a development mode.

Okay. Fair enough. And in -- with the pool and the (inaudible) wells, I mean, what is your guys' sense on why those wells really worked or at least seemed to work pretty good. I mean is it the thickness out there or natural fracture? I mean do you guys have sort of a sense on what could have resulted in such strong rates?

Well, I think the tangible things you can point to is that, when you compare it to the other wells nearby, the lateral lengths were longer. I think 30% or 40% longer and we pumped larger jobs. So those are the tangible things that impact rock contact, and I think that has the most to do with it. Could we be encountering some -- a little more fractured rock, a little bit more of a sweet pot? And certainly that could be part of it, but the things you can put your arms around are the well design.

And you didn't have seismic covering that area. Is that correct? At this time 3-D?

That's correct.

Okay. Thank you.

And we'll go next to David Heikkinen at Tudor, Pickering.

Congratulations on all the hard work. I had a question. The recent wells and the PV - in the pads, though, what's the PVI for the longer laterals?

Well, I don't think we've, we're really set on that. David, obviously the -- we have projected a lot of those wells for the fourth quarter and going forward and we wouldn't be signing the AFPs improving those if they weren't hitting our hurdle rates. So, it's not to be elusive but it's the ultimate from the well costs are where they come down will really determine that, but our model of economics say that they hit our hurdle rates and then some.

It's easily greater than 1.3 is a good enough example. And the deep test in the Fayetteville drill on 3-D, any thoughts of scheduling and any idea of prospectivity for drilling a deep test?

In the deep, the deep section there is to me is very intriguing. Coming up on the expiration side of the business, when I look at that -- look at the seismic and look at the style of the geology in the deep section, it's very, very interesting. We start to get some rotated faults with some reverse throw on them and things setting up for deeper carbonates to be juxtaposed against source bed shales and a very interesting look in geology. In terms of the timing that will be -- those deep tests will really start in '08, early '08.

The interesting thing about that relative to where we'll be positioned today versus where the companies who were pursuing that back in the 70's is that their data sets were just so coarse. The size declines were maybe spaced ten miles apart and they had very little well control.

And so the picture they were able to put together was a pretty gross one. It didn't have a lot of success. I did see gas shows in some of those perspective horizons; but with the 3-D's that we will have here and then far more well data albeit that initially it will be through the Fayetteville depths, we have a better chance certainly of putting together a geological picture down there. But it is exploration and it would be exploration and so it has all the risks and uncertainties associated with it you would expect.

Sounds interesting. The -- just to make sure I'm visualizing that on top of this Rainbow you are drilling six wells northeast or north south and you'll drill one well at the heel and toe, so it's kind of eight wells per section is my mental picture.

Well, no. Well, if you started on the - in terms of trying to paint that picture, if you started on the west side with a well that would be drilled down the section line and then there would be 1, 2, 3, 4, 5 across that, five more across that. So, they'd be six going north south, and then there would be one across the north line and one across the south line. But if you start counting those successively, one to another you can't count any of those wells in each section. So, it really becomes like six wells...

Okay.

... that you would count. On a continuum of that, it would be six wells per section. In other words something in the 100-acre spacing range.

...I think that's awfully fine. As you go section to section, you spaced out. Okay. I got it.

Yes.

Thanks, Al.

And we haven't, we really haven't seen at that space in between wells really haven't seen any kind of classical sharing of reserves? On occasion we've seen the frac job reach out and touch another well and interrupt its production, but then it gets back on its producing trend and so we're not seeing any -- although it's early, we're not seeing any real sharing reserves there so I think it's part of why Harold mentioned that the jury is still out on that spacing.

Yes. What he's saying is we haven't seen any sharing of reserves. What that would mean is we haven't seen interference of one well on another's reserve.

Well, what that might lead you to believe is that you can drill more wells than that per section, but anyway we've got to start somewhere. Another thing this kind of pattern does is it cleans up some of the questions that you would have of trying to drill the northwest diagonals across section line. It becomes a much cleaner thing; it's one of the wonders of Arkansas. There's the spacing units in Arkansas are government sections in one square mile. It allows for the simplistic geometry versus what has to happen in some other states where you cobble together irregular patterns, and then spacing really does start bouncing all over the place.

I hate to ask another question; I'm breaking the rules. So, a 200,000-acre fee land coming up from Anardako, now you guys set an early deal with Anardako. Are you interested in adding more acreage with that type of blocks coming out in a space -- the most your acreage?

Well, generally things like acquiring and leasehold, we just don't talk about what our strategy is.

Fair enough. Thanks, guys.

And we'll go next to Gil Yang at Citigroup.

Hi. I want to drill down a little bit into the better results. It sounds like there's a couple things going on; one is longer laterals and maybe [pin in] off the bigger frac jobs. You may be - and then the third combined would be the benefit of 3-D. Can you separate out the improving results and how much you think is just longer laterals versus frac jobs versus avoiding problem areas.

Well, I think the overriding factor is the longer laterals. The larger -- that's the theme that runs through that body of wells we're talking about.

The larger fracture stimulations have been mostly in the eastern end of the Play, eastern part of the Play where we're looking at the thicknesses of the objectives and the boundary bed conditions and things. Our engineers I think have pretty smartly figured out how they can affect that and that's where the longer -- excuse me -- the bigger fracture stimulations have been. In that area, we're seeing that that's having a pretty good impact.

Well, some of you might remember that over there on that eastern side and parts of it, it's quite thick and some of our results we had reported earlier in past quarters weren't getting that good wells relative to what you would think they should be based on the thickness. And one of our comments about that has been, maybe we didn't have our well horse placed appropriately and/or we hadn't completely gotten in contact with all the rock there.

So the bigger fracs, not only bigger fracs -- when we say bigger fracs, part of the detail of that is also pumping at higher rates which about has something to do with the better sand transport with the use of slickwater. So there may be some things happening there that are important to the equation also.

Now, we can't get away from this question that will, I know will continue to haunt us out there and that might be that we may encounter areas of -- areas where we have better rock and then poorer rock; but we also encounter areas where we have some faults we crack into and resolve in some poorer wells.

And if you look at that, they curve the graph that was put in the press release. There are a couple of wells that were not such good wells that are responsible for that pretty low producing rate on the average normalized curve during the time period when they dominated the data set. So, we've had some that haven't been quite as good also.

But has the 3-D helped you avoid those? Can you -- have you seen experience that tells you that?

Well, we think the 3-D will help us but we don't have 3-D over there yet in that Sharkey area, for example.

But has it helped you in the other areas?

I think the numbers that I saw in some recent reviews were that -- when we're all done with those seven, probably 15% to 20% of the wells we have drilled will actually have been able to utilize 3-D. But next year -- we haven't firmed up our plans, but the way the seismic acquisition's going and where we're likely to be drilling, that number will go way up and so it'll become a more important tool to our drilling.

Yes and, Gil, yes, it does help us. So, where we have the structural picture that certainly helps us where we can avoid faults and also avoid steep structural features that would help -- that help us keep our well bore within the Fayetteville section and then beyond that there may be some additional help out of some of the attribute analysis that we do.

Right. Just one quick question; it's a good question. 170 wells in progress now. Could you just remind us how many were in progress last quarter and maybe a year ago?

I can't. Maybe one of you guys can. I don't have that at the top of my head, Gil, but we can take that question down and get it to you here later today.

All right. Thank you.

And we'll go next to David Tameron with Wachovia.

Hi, good morning. A question for you. Can you talk a little about the distribution of the wells across the Fayetteville? Is the stuff you're drilling is it following a bell curve or kind of what -- what do the tails look like? Just what's the distribution as far as more rates in EURs?

Well, it's -- I think we've talked about the -- when we talk about an average well, it's certainly what gives rise to that average is that we have a pretty wide variance from less to a -- less than a Bcf to well over 3 Bcf. And we look at that in terms of trying to figure out reserves and thing and it's kind of -- we're seeing kind of a lot normal distribution of that.

Okay. So that's fairly (inaudible). So -- I mean, you're talking 15%, 20% of the tails and then kind of a cluster in the middle if I were looking at a bell curve?

Yes, more or less.

Okay. Fair enough. Thanks.

Okay.

And next to Joe Allman of J.P. Morgan.

Hi, again, everybody. I'm trying to get an idea of how much acreage are now focused on. I think you're trying to focus on the areas where you had the best results at this point. Could you kind of -- could you comment on that? Like how much of the, how much of the drilling is going into the best areas and those best areas at this point would be what percentage of your total acreage position?

Well, I think that there's a balance there that we've talked about, Joe. We can't concentrate all the rigs where we're seeing the very highest EUR. It's a program approach but it also requires us to be able to plan long-term and evaluate the acreage and to know what we have across the Play and to hold the acreage, that we're taking a little bit more risk in those areas. They are more exploratory in nature. So, I think probably from a rig count, maybe a way to approach it is that's probably 75% of our rigs are in more established areas right now.

Okay. Any idea what percentage of your total acreage might be those more established areas?

Not really.

Okay. Got you. Okay. And then just in terms of financing -- back to that issue. I mean do you guys expect that you might need to raise equity to fund the Fayettevale Shale and maybe some who knows how the Marcellus Shale is going to work out and the other activity you've got. And then can you comment on that? And what about the ramping up? I mean it seems to me that you might have some people constraints that are really preventing you from ramping up more than you otherwise would. Can you comment on that too?

Yes, Joe, the basic question has a lot of moving parts to it. For example, as we think about 2008, commodity prices are very important. The other important element is at what phase do we decide to move ahead with activity levels in 2008. I can't really comment much on that right now because we're building that plan and we -- it's an (inaudible) process.

We've -- we have the desires I'd say or the plans from the individual teams. We put them together, build it up to the total plan and we look at what will our balance sheet look like under various scenarios. And you have to look at -- you mentioned the people resource. And many of you have heard me talk before about I've for many years have used the oil and the A&EP business as kind of a "teeter totter" with the capital on one end of it and opportunities on the other end of it and very seldom is a company ever completely in balance on that. And sometimes you have more opportunities than you have capital and we have to deal with it -- the capital side of it. And for a lot of companies it's the other way around.

But really, nowadays, we are more like a three-bladed helicopter blade. Capital on one blade, opportunities on the other and the people and equipment resource on the third blade. We have to try to keep all that balanced.

As we think about -- generally about going forward here, the question is the pace of activity. You asked the pace question. We can see what's reasonable levels of capital expenditure in 2008, that we could end 2008 in a very comfortable debt to cap range. So, we don't have to, we don't have to go do something. We would likely want to firm up some of our debt at some point along the way here. But, if we want to go faster and as some of these things that we're working on, if they develop into bigger projects, then -- for example, don't talk a lot, if people don't talk a lot about this right now because the Fayetteville. But the activity we've had in Midway this year has cost us more capital because we've been so successful. We build our plan on the basis of an assumed probability of success. And then when we have total success, then we set pacing in the wells and complete the wells and it's a good news thing.

But when we sum all of it up, the activity levels are going to drive the answer to your question. The good thing for us is we have a lot of options; we have a lot of optionality in regard to funding. We could choose at some point in time to exit a business that we're in or an area that we're at that may be less of a focus for us.

We've talked over time about the -- and not to say this is out there on the market, but we're -- as this Fayetteville unfolds with the large gathering system that we're building here, we may have one of the largest gathering systems in the United States when all this is said and done. That's interesting.

So, there are a lot of ways of dealing with this. The real question for us is, if the Fayetteville Shale is as large as it appears that it is, won't you go faster at some point in time? And the answer to that is that we would want to go faster at some point in time but we need to have our organization built to where it has the capacity and the capability to go faster. We're not there right now.

Okay, that's very helpful. Thank you very much.

(OPERATOR INSTRUCTIONS). We'll go next to Michael Scialla with A.G. Edwards.

Hi, guys. Actually Joe just asked my question on the --where you stood in the hiring process but thanks and great quarter.

Thank you, Mike.

And next to, Robert Christensen at Buckingham Research.

Earlier in the Q&A, I think David Heikkinen's question, you mentioned that you are, I guess, close to considering a deep test of what's in the Arbuckle.

Well, yes, we did mention that, Bob. We have exploratory work going on, on the, on our vast acreage besides just (inaudible) work. And I think the section there that is perspective is immediately below the Mississippian section in the Silurian- Devonian rock and then on down really even into the older rocks. The Arbuckle could have potential, but we're more focused on those intermediate depth carbonates.

And do you think there's odds for such a wildcat in '08?

Yes, we'll be likely testing some wildcats during '08, hopefully early in '08.

If I can have my turn at the Marcellus, did you -- do you have a partner on your lease hold. I mean there's a number of operators up there that have drilled wells vertically from my understanding of it. Did someone bring you in or did you farm in to somebody else's acreage or is it 100% owned?

I don't... Bob, I understand the reason to want to know that. I don't think it's best for us to comment on that. Generally, we don't do a lot of following, though.

Thank you.

(OPERATOR INSTRUCTIONS). Next to, Scott Hanold with RBC Capital Markets.

Hey, thanks. Hey, guys, one more question on drilling longer laterals. I know there's been a lot of talk about where it could be drilled and where there is maybe more perspective. But sort of looking at it a little bit different way, kind of, you kind of look at your drilling say over the next, say, 6 to 12 months, what would you guys sort of anticipate the percentage of the well that you'd drill in the Fayetteville be at lengths of 3,000 plus feet on the -- for the horizontal portion.

I think the jury is out on that until we finish our plan, but a question -- the topside question that we would have is, if we're really getting high EURs, what it looks like in better economics, why would we do anything but those? That would be their starting premise and now there will be some reasons and some logistical things that come into play, but we'll certainly push in that direction.

Okay, thank you.

And next to Joe Magner at Tristone Capital.

Good morning. Just one more, in terms of average working interest or net revenue interest we can assume across the -- I think in October, your net was about 75% of total production. Is that a reasonable number to use on future activity?

That's a reasonable number, yes.

Okay. Was it very much across the area from areas where you're having a lot of success to some of the outlying pilots and will it shift much or--?

It's a pretty complicated picture. I mean it varies by section, but geographically I wouldn't say that we have a fundamental change in interest levels.

Yes, now on the outside operated, it -- of course where Chesapeake's operating or (inaudible) or someone else, then we may only have 5% or 10% on those. So the mix of our activity will dictate that to some extent. So it depends on activity levels of those other companies and -- in our total, but on our operated I think it's fairly consistent at this point.

Okay. Thank you.

And, gentlemen, that does conclude our question-and-answer session today. I would like to turn the conference back for any closing or additional comments you'd like to make.

Well, thank all of you for joining us today. Clearly, we had a very good quarter to report here as the kind of level of activity and our assessment part of our drilling here continues. And as we're moving some of these -- moving forward with -- moving more towards the development, I guess I would say, and there'll be a lot of interesting things to unfold likely as we go on forward on the demo project area. Thank you.

This does conclude today's conference. We do thank you very much for your participation. You may disconnect at this time.