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Southwestern Energy Co. (NYSE:SWN)

Q3 2007 Earnings Call

November 01, 2007, 10:00 AM ET

Executives

Harold M. Korell - Chairman, President, and CEO

Richard F. Lane - EVP and President

Greg D. Kerley - EVP and CFO

Analysts

Jeffrey Hayden - Pritchard Capital Partners

Thomas Gardner - Simmons & Company

Joseph Allman - JP Morgan

Amir Arif - Friedman, Billings, Ramsey& Co

Brian Singer - Goldman Sachs

Scott Hanold - RBC Capital Markets

David Heikkinen - Tudor Pickering

Gil Yang - Citigroup

David Tameron - Wachovia Capital Markets

Michael Scialla - A.G. Edwards

Robert Christiansen - Buckingham Research

Joseph Magner - Tristone Capital

Presentation

Operator

Please standby we are about to begin. Good day everyone and welcome to Southwestern Energy Companyís Third Quarter Earnings Teleconference. Todayís call is being recorded.

At this time, I would like to turn the conference over to President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead sir.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Good morning and 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 youíve 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 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 filing 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 couldnít help but reflect on the changes in our Company over the past few years. Nearly 10 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 at this, evidence by our developments at the Ranger Anticline in Arkansas, our East Texas activities at Overton, and in a big 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 facts and with the benefit of our growing 3-D seismic knowledge.

In the Fayetteville, we are building the database of production history on our wells and we are 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 fracture 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.

Richard F. Lane - Executive Vice President and President

Thank you, Harold. Good morning. During the third quarter, our natural gas and crude oil production totaled 30.0 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 on September 30th 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, 15 deep and 4 shallow rigs in the Fayetteville Shale Play, 6 rigs in East Texas, one in North Louisiana, one in the Permian Basin and 4 in our the conventional Arkoma Basin activities.

Back to 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, they are 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 to drill 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 million last quarter that we completed in the last quarter, thatís due to drilling and completing wells with longer horizontal laterals and larger fracture stimulations. Although, our average total well cost for the quarter was up. We have reduced our drilling and completion costs on a dollar per foot basis quarter-on-quarter. Lateral lengths for third quarter wells averaged 2,613 feet compared to 2,497 feet in the 2nd quarter.

In the third quarter, we began to see improved performance due to shifting the focus of our drilling activity to areas that have been identified as better performing to date and where 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 stimulations and approximately 20% of the completions used open-hole packer systems. Now these wells have confirmed our analysis that indicated that both the slickwater and the open-hole packer systems yield better performing wells. We are also seeing better well results from drilling 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 provided 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 the average gross estimated ultimate recovery from wells with greater than 3,000 foot laterals to range from 2.0 to 2.5 Bcfe per well.

Approximately 26 million cubic feet per day of our current production is from three of the Company's easternmost 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 wells on production with production rate of over 5 million cubic feet per day. The Poole #1-15H in our Sharkey pilot area, 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 Featherston #1-22 well also in the Sharkey, fracture stimulated along an open-hole packer 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 design to test longer laterals, concentrated well activity, multistage drilling, and some efficiencies we can gain from our operations, and we will report more on that as that holds 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 are continuing to put good wells on production at our Ranger Anticline and Midway field. And as a result, production from both 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 3 rigs at Overton, and 3 rigs at our other project areas. In the first nine months of 2007, we invested approximately $150 million drilling 35 wells at Overton and 21 wells at Angelina River Trend, four wells at our Jebel 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 Bcfe last year.

To date, we have now spudded five wells on our Jebel acreage block in Shelby County, Texas. Three of these wells were drilled to the Travis Peak formation and two are horizontal wells targeting 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 Timberstar Worsham well has been completed in the James Lime and is flowing to sales at a rate of 12.2 million cubic feet equivalent per day. We hold a 21.5% working interest in this well. And the Timberstar Mills #1H, which we operate with a 100% working interest, is drilling and we expect to reach total depth in the fourth quarter. And pending the results of both the Travis Peak and James Lime wells there maybe significant drilling potential in 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 age 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.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Thank you Richard and good morning. Our earnings for the third quarter were $51 million or $0.30 per 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 in 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 30.0 Bcfe in the third quarter and realized an average gas price of $6.66 per Mcf, which was up $0.43 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 fixed price swaps and collars, provides us with support for a strong level of 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 hedged with fixed price swaps at an average price of $8.09 and we have 10.5 Bcf hedged 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 10-Q.

Our lease operating expenses per unit of production were $0.67 per Mcfe during the third quarter, down slightly from last year, but almost down $0.15 lower than our previous guidance. Our LOE was lower than we expected due in part due to a decrease in the cost of fuel gas for compression related expenses, partially offset by increases in gathering costs, both primarily related to our operations in the Fayetteville Shale play.

General and administrative expenses per unit of production were $0.46 per Mcfe in the third quarter, down from $0.54 in the prior year period. The decrease was primarily due to increased production volumes. Taxes other than income taxes per unit of production were $0.11 per Mcf during the third quarter, down from $0.32 in the prior year period due to change in the mix of our production. Our full cost pool amortization rate was $2.56 per Mcfe 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 320 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. So, I will turn back to the operator who will explain the procedure for asking questions.

Question and Answer

Operator

Thank you, sir. Todayís question-and-answer session will be held electronically. [Operator Instructions].

And we will go first to Jeff Hayden at Pritchard Capital Partners.

Jeffrey Hayden - Pritchard Capital Partners

Hey, guys. Congratulations on the great quarter.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Thank you.

Jeffrey Hayden - Pritchard Capital Partners

Real quick. Just looking at some of those trends 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 ball pilot I think that was the Reaper #1-12. Could you just [inaudible] 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?

Richard F. Lane - Executive Vice President and President

Well, the distÖ I donít know the exact distance to that, itís not too far, itís probably about 5 to 10 miles north of Reaper where these Sharkey wells that we reported on. So, itís basically they areÖ both eastern most pilot areas, if you will, and the Sharkey wells would be a little bit north of that Reaper well. And Iím not sure the exact rig count I think we have two or three of our rigs active over in that eastern area right now.

Jeffrey Hayden - Pritchard Capital Partners

Okay. Thanks a lot guys.

Operator

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

Robert Christiansen - Buckingham Research

Good morning.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Good morning

Robert Christiansen - Buckingham Research

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

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Rob, this is Greg. The CapEx is as we have said in our press release, we are looking atÖ we probably are about $110 million above our earlier projections for the full year, and that's obviously is our run rate and our increasedÖ completion link, 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 total E&P dollars of invested this year, we expect to be about $1.3 billion. And then in Midstream side, weíll be up to about a $100 million versus about $84 million, $85 million originally projected there, just due to increase the pipe weíre putting in the ground and with increased activity.

Robert Christiansen - Buckingham Research

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

Harold M. Korell - Chairman, President, and Chief Executive Officer

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, weíve had over $3 million of tax credits received from the state of Texas, right to some changes in the law. There was capÖ $1 million cap on refunds, and so those areÖ thereís a big chunk of that that really related to 2006. So, we have kind of a win fall that really helped our rate brought down and then just changing mix of our production.

Robert Christiansen - Buckingham Research

Thank you. Weíll get back in line.

Operator

And weíll go next to Tom Gardner at Simmons & Company.

Thomas Gardner - Simmons & Company

Good morning, guys.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Good morning.

Richard F. Lane - Executive Vice President and President

Good morning.

Thomas Gardner - Simmons & Company

Just with respect to this 24 longer lateral wells, are thoseÖ have those been drilled sort of in a widely distributed pattern, or has it been concentrated in just various areas.

Richard F. Lane - Executive Vice President and President

Itís a pretty wide spread. I think there is 10 different pilot areas that account for those 24 wells. So, itís across the play pretty much.

Thomas Gardner - Simmons & Company

Moving over to the Marcellus Shale, just wanted to kind of give an idea of the competitive landscape and what might be your focus areas there? And several questions along those lines that. But I just let youÖ tell me what you can tell me and then is your planed well next year likely to be horizontal or vertical?

Richard F. Lane - Executive Vice President and President

I would say I probably wonít tell you much more than whatís in that press release for some obvious reasonsÖ competitive reasons. And we are active there. I think weíll start out with vertical pilot well to gather data and then likely move to some horizontal drilling.

Thomas Gardner - Simmons & Company

Iíll jump back in line.

Operator

And we go next to Joe Allman of JP Morgan.

Joseph Allman - JP Morgan

Hi. Good morning everybody.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Hi Joe.

Joseph Allman - JP Morgan

In terms of Jonah 3,000 plus foot laterals. Over what acreage, and I know Richard you 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? Or could you talk about maybe 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 the play?

Richard F. Lane - Executive Vice President and President

Well, I think the acreage or the area where we would drill themÖ what we are seeing there, Joe, is that maybe we have better wells there that we can have higher EURs in. That would be give us better economics. So, we wouldÖ if that holds true, we would try to find all the acreage we can. We donít see any kind of geographic bias for that. So, we would try to approach to play as we have from the start. We are trying to improve the well results and how we are doing them, and I think itís applies to the whole acreage. Obviously, we have some acreage that we developed already and some spacing determents made there. But I think it applies to the whole play.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Joe, maybe just to add a little bit to that, Richard. If you think about the build up scenario that weíve been and over time here, if you move all the way back to two years ago or when weÖ just weíre starting drilling and started drilling horizontal wells across a very board area where we didnít have any data yet. The obvious thing for us to do and weíve talked about this over these teleconferences, over the past couple of years, when we are removing in the new areas, we would generally drill a pilot hole and then a couple of thousand foot lateral because it didnítí make a lot of sense to risk, trying to drill a 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 begin to drill some longer laterals. They are interesting developments that they generally take place as you think about the geometry of the wells that we are drilling. And itís a lot of details that try to paint a word picture for you over the phone. But generally ourÖ the orientationÖ the direction of our horizontals has been in north-westerly direction and units are spaced here on government sections. And so, that would have allow you when you went into the first well and in a section, you might generally drill a shorter lateral because you drill it at near, one of the corners, and then later you would think in terms of drilling the longer laterals.

In thisÖ what Richard mentioned earlier, this, what we are calling infernally here a demo project in Southeast Rainbow. We are taking basically a four section part of our acreage, four government sections. And we are going to be using inside a different orientation to our wells, we are going to be drillingÖ he mentioned, drilling multiple wells off of single pad. We will be drilling wells in our north-south orientation. If you think about 1 square mile and think about putting the surface location along say the northern border of the 1 square mile and then drilling wells both north and south off that, with an attempt to drill as longer laterals is possible spacing them approximately for this test, the well bore is approximately 1,000 feet apart parallel to each other cross back section. And then ultimately having an east-westerly well, that would pickup reserves and otherwise wouldnít be drained along the northern section line.

So, your question about spacing, we donít know the ultimate development spacing here. We have talkedÖ at times about 80 acre spacing which would mean eight 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 wouldnít be drained during the return part of the well, which you would drill in an east-westerly direction along, the northern boundary. Then 1,000 feet apart, you can think of if you keep sequencing that across sections that you would have maybe six 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 donít know thatís the absolute answer, but we are going in with that kind of test. And we will see what it shows us. And we are beginning that activity now. Stations are build for drilling wells and that will all unfold now over the nextÖ basically six to eight to 10 months, a year, as it will take that time to get all this done. The other thing is we will be able to see in doing that are whether our cost going to be when we get concentrated on development. And by the way, we havenít been concentrating on development. We still got acreage to assess. So itís going to be a lot more interesting information come out. It might tell us that that the 1,000 foot spacing between horizontal is to far and it might mean that ultimately want tighter spacing. Itís a big project. We have a lot of work to do. But we think we are approaching at the right way with this particular test.

Joseph Allman - JP Morgan

On the [inaudible], Harold and I appreciate that. In terms of shallow conventional, could you talkÖ that place isÖ going to be pretty well. Could you talk about how extensive that plate might be? And is that formationÖ is thatÖ you think it might be continuous across a lot of your acreage position?

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Joe, the general packages are continuous across the acreage. The individual sands that we are finding areÖ there isÖ for sure a stratogophic [ph] component to them and they will be variable across the acreage. I think the really good thing is that we have seen Atoka and Morrow sand production pretty much across the whole play. And so, we know itís not isolated, it is just one little part of our acreage there. And the other thing is that weíve seen some really nice rates from those wells, that time on stimulated rate that are 3 and 4 million cubic feet per day. So, the jury still out on how extensive itís going to be. The things that are point in a good direction is that we found it over pretty broad area and now we areÖ just now really working that harder. I think 3-D seismic will be a nice benefit for us there. And that we are hopeful to find some sizable stimulation there.

Harold M. Korell - Chairman, President, and Chief Executive Officer

The good news about it is we get to look at it as we are drilling wells down to the Fayetteville. And so, we find that, we can stop and complete it. The other beauty of it is that they are currently inexpensive and about $600,000 or $700,000 of well. And they also help us earn acreage as we do though. 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 and hold an earning acreage as well as providing some very nice cash flow that is a good thing.

Joseph Allman - JP Morgan

I appreciate that. Thanks, guys.

Operator

[Operator Instructions].

And we will go next to Amir Arif with Friedman, Billings, Ramsey.

Amir Arif - Friedman, Billings, Ramsey& Co

Good morning, guys. Congratulations on a great quarter. Richard, I know you said you donít have much to say right now on the Marcellus Shale, but can you just give us a sense of how many wells you're looking at drilling in the first half?

Richard F. Lane - Executive Vice President and President

Amir, I donít really have a lot more to share with you there. Itís going to really depend on the testing that we do in some of these first wells and gathering the real core data there for rock properties and all that. And that will really determine those levels of activity.

Amir Arif - Friedman, Billings, Ramsey& Co

If at all you do find a start drilling some well, is it Q1 í08, or we're just talking some time early in May?

Richard F. Lane - Executive Vice President and President

Yes, I think weíll start permitting here before the end of the year and hopefully get them going early in í08. We got some weather issues there to deal with as well.

Amir Arif - Friedman, Billings, Ramsey& Co

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

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Yes, Amir. This is Greg. Things are going really well there. As far as the Boardwalk pipeline. They submitted their first application. They have over half of right away purchase Theyíve actually gotÖ have sent delivery of pipe, thatís currently being coated. So, we're real pleased thatís right on schedule where our participation was at this time. We alsoÖ just to remind again thereís the two other lines inÖ those are client, has the capacity of 330 million a day. We hold about 325 million of firm on that line, and a Center Points [ph] line that runs along the south of the play, has a capacity of about 250 million. The firm on that has already subscribed to, but we can move gas to the ultimate end users on that also.

Harold M. Korell - Chairman, President, and Chief Executive Officer

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

Amir Arif - Friedman, Billings, Ramsey& Co

It sounds good. Thanks.

Operator

And we will go next Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you good morning.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Good morning.

Brian Singer - Goldman Sachs

Can you talk to where you think your drilling completion cost would be at 3,000 foot lateral well at Fayetteville? And then where do you feelÖ 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?

Richard F. Lane - Executive Vice President and President

Yes. Brian. Well, I could tell you probably a good anchor number there is the 24 wells that we 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 now little more than half probably 55%, 60% thatís completion. In terms of where we are on maturity of drilling cost and gaining efficiencies, I think a lot of that has to do withÖ or is controlled by what Harold talked about earlier, we are really not in the development phase yet. This demo project was start to do that, but because we are stepping out into a lot of new areas and have a lot of diverse conditions that were having to deal with there, we are really not in the factory mode yet. So, we are not seeingÖ although, we are seeing some efficiencies quarter-on-quarter like we reported, we are not really in that hardcore development mode where we would expect that we would drive those cost down. I canít tell you how much it will come down, I will say that another projects where we define the development mode, we have been able to do very well to drive those cost down.

Brian Singer - Goldman Sachs

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

Harold M. Korell - Chairman, President, and Chief Executive Officer

Well, the first thing is we donít use the term spending. But Brian, we useÖ we always call it interesting. And I have said around here that we matched people funds when they say itís pending I know thatís a word people use. But we think about it as a investing, but Greg Iíll let you answer the question about that otherwise.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Yes, we are going to drill our face all of this, because thatís been a internal joke what I will refer for years, but we think we are very well positioned, Brian, right now. We talked about and we have given our guidanceÖ and about where we are as part of the year, we are going to be clearly user of debt capacity this year and thatís worked out. Our cash flow is running higher than our projections were as gas prices have been a little better, I hope something little bit better for us. And our CapEx is up a little bit, but we will be about exactly kind of where we projected beginning of the year. I mean as we havenít build our plan for 2008 right now, itís in the process. We are looking very hard to that, obviously, andÖ but we stillÖ as even though our cash flow as production growth over 50% this year and we will have in the year, strong number and obviously have some strong numbers in 2008, we wouldnít been anticipate their cash flow quite equals our CapEx run. So, we will still be incurring some levels of debt, but still within a very reasonable capital structure.

Brian Singer - Goldman Sachs

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

Operator

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

Scott Hanold - RBC Capital Markets

Thanks good morning.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Good morning.

Scott Hanold - RBC Capital Markets

You guy have obviously in the past have talked about doing different things as far as doing your inflation and it sounds like you have a unit demo where you are going to do some pad drilling. Can you sort of talk about any efforts in trying the stimul frac or have you tried that, or do you expect to here over the next quarter?

Richard F. Lane - Executive Vice President and President

Yes, weíve had limited experiments with that. We have actuallyÖ what we have done there is just a few wells and we really havenítÖ it depends on what you call stimul frac weíve done kind of two wells back to back, but maybe not alternated the stages. So, we are actually doing two wells at the same time and alternating the stages. Thereís 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.

Harold M. Korell - Chairman, President, and Chief Executive Officer

I think one of the constraints on us doing that is we havenít drilled a large number of wells that are like sitting side-by-side, and again, that's because we are not down to that sort of spacing generally across the play because we still have our drilling rigs relatively more spread out. Thatís an open field I guess on that and I know thereís been discussion internally that in the demo project that would afford us really our first opportunity that to be able to gather that type of data in our area.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

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

Scott Hanold - RBC Capital Markets

Okay. Fair enough. And with the Poole and southern [ph] wells you meanÖ what is you guys sense on why those wells really workedÖ really at least, seem to work pretty good. I mean, is it the sickness out there or natural fraction? I mean you guys have sort of a sense on what could have resulted in such strong rates.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Well, I think the tangible things you can point to is that when you compare it to the other wells near by 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 little more fractured rock, a little bit more on the sweet spot and certainly that could part of it, but the things you can put your arms around are the well design.

Scott Hanold - RBC Capital Markets

And you didnít have seismic covering that area. Is that correct at the same 3-D?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Thatís correct.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Operator

And weíll go next to David Heikkinen of Tudor Pickering.

David Heikkinen - Tudor Pickering

Congratulations on all the hard work. I had a question the recent wells in the TD Öin Fayetteville, what is the TDI for the longer laterals.

Richard F. Lane - Executive Vice President and President

Well, I donít think weíve really set on that. David, obviously theÖ we have projected a lot of those wells for the fourth quarter and going forward and we wouldnít be signing AFEs and proving those if they werenít hitting our hurdle rate. So, itís not to be illusive, but the ultimate in the well cost areÖ were they come down or early determine that, but our modeled economics say that they hit our hurdle rates and then some easily greater than 1.3 is a good enough example.

David Heikkinen - Tudor Pickering

And the deep test in the Fayetteville on 3-D, any thoughts of scheduling and any idea of prospectively for drilling a deep test.

Richard F. Lane - Executive Vice President and President

The deep section there is, to me is very intriguing. Coming up on the exploration side of the business when I look at thatÖ I look at the seismic and look at the style of the geology in the deep section. Itís very, very interesting. We start to get some rotated bulbs with some reversed drill on them and things setting up for deeper carbonate to be just posed against source bed shales and very interesting looking geology. In terms of the timing that will beÖ in all those deep test will really start in í08Ö early í08.

Harold M. Korell - Chairman, President, and Chief Executive Officer

The interesting thing about that relative to where we will be positioned today versus where the companies who are perusing that back in the 70s, as their data sets, were just so coarse. The seismic lines were maybe spaced to 10 miles apart and they had very little well control. And so, the picture they were able put together was a pretty gross one. They didnít have a lot of success, we did see gas shales in some of those perspective horizons, but with the 3-D that we all have here and then far and more well data, albeit, that initially it will be through the bed well debts. We have a better chance certainly to put the together a geological picture down there. But it is explorationÖ it would be exploration and so it has all the risk and uncertainties associated with it that you would expect.

David Heikkinen - Tudor Pickering

It sounds interesting. Just to make sure I am visualizing that Southeast Rainbow, you are drilling six well on the north-eastÖ north-south and weíll drill one well at the Allentown so, itís kind of eight wells per section is my metal picture.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Now I think, well, if you started on theÖ and trying to paint that picture, if you started on the west side with the well that would be drilled down the section line. And then there would be 1, 2, 3, 4, 5 across that, 5 more across that so there would be 6 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 canít have all those wells in each section. So, it really becomes like six wells.

David Heikkinen - Tudor Pickering

Okay.

Harold M. Korell - Chairman, President, and Chief Executive Officer

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.

David Heikkinen - Tudor Pickering

Awfully flying, and thatís the, as you go section-to-section--?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes.

David Heikkinen - Tudor Pickering

Okay. I got it. Thanks, Harold.

Richard F. Lane - Executive Vice President and President

And that we havenít seen, we really havenít seen at that spacing between wells, really havenít seen any kind of classical sharing of reserves. On occasion, we have seen the frac job reach out and touch another well, and interrupt its production, but then it gets back on and just producing trend, so, we are not seeing anyÖ although, itís early we are not seeing any real sharing of reserves there. So, I think, itís part of what Harold mentioned that, jury still out on that spacing.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes. We havenít seen any sharing of reserves, what that would mean is we havenít seen interference of one well to another on those reserves. What that might lead you to believe is that you drill more wells than that per section. But anyway, we have 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 north-west diagonals across section line. It becomes a much cleaner thing. Itís one of the wonders of our Arkansas. Itís spacing units in Arkansas are government sections and it is 1 square mile. It allows for this simplicity geometry versus what has to happen in some other states where you couple together irregular patterns and then spacing really does start bouncing all over the place.

David Heikkinen - Tudor Pickering

I hate to ask another question, and I am breaking the rules. So, 200,000 acre free land coming up from Anadarko. Now you guys did an early deal with Anadarko. Are you interested in adding more acreage with that type of blocks coming out and it inter space to monster acreage?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Well, generally things like acquiring and lease hold, we just donít talk about what our strategy is.

David Heikkinen - Tudor Pickering

Fair enough. Thanks guys.

Operator

And we will go next to Gil Yang at Citigroup.

Gil Yang - Citigroup

Hi. I wanted to drill down a little bit into the better results. It sounds like there is a couple of things going on. One is a longer laterals and maybeÖ and then also I think frac jobs. Can you maybeÖ and then the third component would be the benefit of 3-D. Could you separate out the improving resultsÖ how much you think is longer laterals versus frac jobs versus avoiding 12 million [ph].

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Well, I think the overwriting factor is the longer laterals. The largerÖ that the being that run through that spotting wells we are talking about. The larger fracture stimulations have been mostly in the eastern end of the playÖ eastern part of the play where weíre looking atÖ the thicknesses of the objectives and the boundary bed conditions and things. Our engineers, I think pretty smartly figured out that how they can effect that and thatís where the longerÖ excuse meÖ the fracture stimulation have been and that areasÖ we are seeingÖ that having a pretty good impact.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Well, some of you might remember that over there at eastern side parts of itÖ itís quite big and some of our results we have recorded earlier in past quarters werenít getting that wells relative to what you would think they should be based on the fitness and. And one of our comments about that has been, may we didnít have well bore basedÖ and/or we hadnít completely got in contact with all the rock there. So, the bigger fact, not only bigger facts, when we say bigger facts, part of the detail is that is also pumping at higher rate, which has something to do with the better sand transport when they use the slickwater. So, there maybe some things happening there that are important to the equation also.

Now we canít get away from this question that we willÖ I know we will continue to counter out there and that might be that we may find areas ofÖ the areas where we have better rock and then ore rock. And we also counter areas where we have some fault frac into and result in some poor wells. And if you look at that the curve the graph that was put into press release, there are couple of wells, that were not such good wells that are responsible for that pretty low producing rate on the average normalize curve during the time period when they dominated the data set. So, weíve had some that havenít been by as good also.

Gil Yang - Citigroup

But has the 3-D help you to believe thoseÖ can youÖ have you seen experience that tell you that?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Well, we think the 3-D will help us, but we donít have 3-D over there yet in that Chorika [ph] for example.

Gil Yang - Citigroup

But have you have in the other areas?

Richard F. Lane - Executive Vice President and President

I think the numbers that I saw and some recent reviews were thatÖ overall done with ë07 probably 15% to 20% of the well we drilled in the last week, enable to utilized 3-D. But next year, we havenít firmed up our plan. But the way the seismic acquisition is going and where weíre likely be drilling, that number will go way up. And so, it will become a more important tool to your drilling.

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes. And Gil I guess it does help us so where we have the structural picture. That certainly helps us where we can avoid faults and also avoid structural features that would helpÖ that help us keep our well bore within the Fayetteville section and then beyond that there maybe some additional help out of some of the attributed analysis that we do.

Gil Yang - Citigroup

Right. Just one quick question. Last quick question is 170 wells in progress now could you just remind us how many were in progress last quarter and maybe a year ago?

Harold M. Korell - Chairman, President, and Chief Executive Officer

I can't maybe, one of you guys can.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

I had that at the top of my head Gil. But we can, take that question down and get it to you later today.

Gil Yang - Citigroup

All right. Thank you.

Operator

And weíll go next to David Tameron with Wachovia.

David Tameron - Wachovia Capital Markets

Hi, good morning. 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. What does the tail look like just what's the distribution as far as well rates and EURs.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Well, itís I think we talked about the, when we talk about an average well that certainly what gives rise to that average is that we have a pretty wide variance from less than 1 Bcf to well over 3 Bcf. We look at that in terms of trying to figure out reserves and thing and we're seeing kind of a lock normal distribution of that.

David Tameron - Wachovia Capital Markets

Okay. So thatís fairly locked. So, I mean you talk on 15%, 20 % of the pails and then kind of a cluster in the middle if I were to look at the bell curve?

Greg D. Kerley - Executive Vice President and Chief Financial Officer

More or less.

David Tameron - Wachovia Capital Markets

Okay. Fair enough. Thanks.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Okay.

Operator

And next to Joe Allman with J P Morgan.

Joseph Allman - JP Morgan

Hi, again, everybody. Iím trying to get an idea of how much acreage you're now focused on and I think you're trying to focus on the areas where you had the best results at this point. Could you kind of 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 beÖ what percentage of your total acreage position.

Richard F. Lane - Executive Vice President and President

I think it is the balance there that we've talked about Joe. We can't concentrate all the rigs where we're seeing the very highest EUR itís 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 and more exploratory in nature. So, I think probably from a rig count maybe a way to approach it is that probably 75% of our rig there in and more established areas right now.

Joseph Allman - JP Morgan

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

Richard F. Lane - Executive Vice President and President

No. not really

Joseph Allman - JP Morgan

ThatísÖ okay. And then just in terms of financing back to that rescue. I mean do you guys expect that you might need to raise equity to fund the payable sale and maybe someÖ who knows how that Marcellus shale is going to work out and the other activity you have got and then just can you comment on that? And what about ramping up? I mean it seems to me that you might have some people constraints that really preventing you from ramping up more than you otherwise would, could you comment on that too?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes, Joe, the basic crush 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 pace do we decide to move ahead with activity levels in 2008, canít really comment much on that right now because we are building that plan and weÖ itís an intuitive process we have the desires I would say are the plans from the individual team. 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 we have to look atÖ you mentioned the people resource. How many of you have heard me talk before aboutÖ for many years I have viewed the E&P business as kind of a titter-totter with the capital on one end of it and opportunities on the other end of it, and very seldom as a company, are completely balanced on that. Sometimes you have more opportunities and you have capital and you have to deal with the capital side of it and for a lot of companies itís the other way around. But really now a days 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 whatís reasonable levels of capital expenditure in 2008 that we could end 2008 in a very comfortable debt-to-cap range. So, we donít 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 are working on. if they developed into bigger projects, and for example, don't talk a lot ofÖ people don't talk a lot about this right now because of the Fayetteville but the activity weíve had in Midway this year has cost us more capital because weíve been so successful. We build our plan on the basis of 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 that, 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 are in or an area that we are at, that may be less of a focus for us. Weíve talked over time about theÖ and not to say this is out there on the market but weíre as this Fayetteville hole unfolds with the large gathering system that we are 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, wonít 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 capacity and the capability to go faster. We are not there right now.

Joseph Allman - JP Morgan

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

Operator

[Operator Instructions]. Weíll go next to Michael Scialla with A.G. Edwards.

Michael Scialla - A.G. Edwards

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

Harold M. Korell - Chairman, President, and Chief Executive Officer

Thank you Mike.

Michael Scialla - A.G. Edwards

Bye.

Operator

And next, to Robert Christiansen, at Buckingham Research.

Robert Christiansen - Buckingham Research

Earlier in the Q & A I think David Heikkinenís question, you mentioned that you, I guess close to considering a deep test, what to the Arbuckle?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes we did mention that Bob, we have exploratory works going on, on theÖ on our vast acreage, besides just Fayetteville work, and I think the section there that is prospective is immediately below the Mississippi, in section, in slower Devonian rocks and then on down really even into the older rocks, the Arbuckle could have potential, but we are more focused on those intermediate depth carbonates.

Robert Christiansen - Buckingham Research

And do you think thereís odds for such a well cap in í08?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes. Weíll be likely testing some wild gas during í08, and hopefully early in í08.

Robert Christiansen - Buckingham Research

If I can have my turn at the Marcellus. Did youÖ do you have a partner on your leasehold. I mean there is 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 into somebody elseís acreage or is it a100% owned?

Harold M. Korell - Chairman, President, and Chief Executive Officer

I donítÖBob, I understand the reason to want on to know that. I donít think its best for us comment on that. WeÖ generally we donít do a lot of following though.

Robert Christiansen - Buckingham Research

Thank you.

Operator

[Operator Instructions]. Next to Scott Hanold, RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Hey Thanks. Hi guys. One more question on drilling longer laterals, I know there has been a lot of talk about where to be drilled and whether it is more maybe prospective but certainly looking at it a little bit different way, you kind of look at your drilling, say over the next 6 to 12 months. Where would you guys sort of anticipate the percentage of the wells that you drill in the Fayetteville. B, at lengths of 3000 plus feet on the latter, for the horizontal portion.

Harold M. Korell - Chairman, President, and Chief Executive Officer

I think, it varies out on that till we finish our plan but questionÖ the top side question that we would have is if we are really getting high EURs is what it looks like and better economics, why would we do anything but those. That will be the starting premise and now there will be some reasons and some logistical things that come into play but weíll certainly push in that direction.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Operator

And next to Joe Magner at Tristone Capital.

Joseph Magner - Tristone Capital

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

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Thatís a reasonable number, yes.

Joseph Magner - Tristone Capital

Okay. And is it very much across the area from areas where you are having a lot of success through some of the outlying pilots and will it shift much orÖ ?

Harold M. Korell - Chairman, President, and Chief Executive Officer

Yes itís a pretty complicated picture. I mean, it varies by section but geographically I wouldnít say that we have a fundamental change in interest levels.

Greg D. Kerley - Executive Vice President and Chief Financial Officer

Yes. Now on the outside operated. Of course, where Chesapeake operating or XTO or someone else, then we may only have 5% or 10% on those. So, the mix of our activity will dictate that some. So, it depends on activity levels of those other companies. And in our total, we donít know operated, I think weÖ fairly consistent at this point.

Joseph Magner - Tristone Capital

Okay. Thank you.

Operator

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

Harold M. Korell - Chairman, President, and Chief Executive Officer

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 for moving some of theseÖ moving forward withÖ moving more towards the development I guess I would say and there will be a lot of interesting things to unfold I believe as we go on forward on the demo project area. Thank you.

Operator

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

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