西南能源 (SWN) 2005 Q2 法說會逐字稿

Good day and welcome to the Southwestern Energy Company second quarter 2005 earnings conference. I'd like to turn the conference over to President, Chairman, and CEO, Mr. Harold Korell. Please go ahead.

Good morning and thank you for joining us. With me today are Richard Lane, Executive Vice President of our E&P company, and Greg Kerley, our Chief Financial Officer. If you've not received a copy of the press releases as we announced yesterday, call Annie at 281-618-4784 and she'll fax a copy to you.

Also I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risks and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would warn you these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially. Well, to begin with things have gone pretty well for us during the first six months of 2005.

Yesterday we reported earnings for the second quarter of a record $26.8 million, up 29% from the same period last year. Our cash flow for the second quarter was also up 29% from a year ago, to a record 65.1 million. These results have been primarily driven by the current commodity price environment, and by the strong growth in our production volumes.

In our E&P program we continue to have excellent drilling results at Overton Field in East Texas, and the Ranger anticline in the Arkoma basin. In the Fayetteville Shale play, we have made progress in our understanding of horizontal wells, established production in six pilot areas and are now drilling in a seventh pilot and completing a well in the eighth pilot area. In addition we have obtained field rules for three fields in total, and are now producing at a gross daily rate of 10 million cubic feet per day. As we announced yesterday we are preparing to accelerate our drilling program in the Fayetteville Shale.

In addition to the purchase of new drilling rigs for the play, we have increased our capital program for the Fayetteville Shale from approximately $100 million to $127 million for 2005, to fund our drilling program and to continue our leasing efforts. We now plan to drill 80 to 90 wells in 2005 in the Fayetteville Shale play, with approximately 50 of these wells being horizontal.

We also plan to increase our drilling activity at Overton, our other East Texas areas, at the Ranger Anticline, and in the Permian basin. Richard will talk about the capital plan and give an update on our E&P operations in a moment.

Overall I'm very pleased with what we accomplished to date and look forward to what lies ahead for us in 2005 and beyond. I'll now turn the teleconference over to Richard Lane, who will tell you more about our E&P results, and then Greg Kerley to discuss our financial results, then we'll answer questions.

Thank you Harold, and good morning. Production for the second quarter was 15 Bcfe, up 19% from the 12.6 we produced in the second quarter of 2004, and up 7% from the 14 we produced in the first quarter of this year. Of the 15 Bcfe of the second quarter production, 6.5 was from East Texas, 5.2 from our conventional Arkoma basin properties, 1.8 from the Permian basin, 1.1 from the Gulf Coast, and 0.4 from our Fayetteville Shale play.

Production during the second quarter of 2005 included continued effects of curtailment of production at our Overton Field. This curtailment issue was resolved late in the quarter and current gross production from Overton is approximately 100 million cubic feet per day, as compared to about 80 to 90 million cubic feet per day, while we were being curtailed. We continue to be very active in East Texas and in the Arkoma Basin. Particularly in our Ranger anticline field, and our Fayetteville Shale play.

Year-to-date, we have spuded a total of 119 wells, including 43 wells in East Texas, 22 wells at Ranger, and 30 wells in our Fayetteville Shale play. We currently have 6 rigs running in East Texas, 4 at Ranger and 3 in the Fayetteville Shale, and expect to increase our Fayetteville Shale rig count through the remainder of the year.

As a result of strong E&P revenues and our inventory of high PVI drilling projects, we have increased our E&P 2005 capital budget from 339 million to $425 million. This $86 million increase includes 27 million for additional drilling and land in the Fayetteville Shale play, 15.5 million for East Texas drilling, 5.6 million for Ranger Anticline, and $4.2 million for the Permian basin. The remain $33.8 million is for the purchase of five new land drilling rigs plus associated equipment, that we announced at the beginning of July.

Moving to our shale play, in the first half of 2005 we invested approximately $55.3 million in the play including 33.3 million to drill 30 wells, and 19.1 million for lease-hold acquisitions. As of June 30th, we held approximately 690,000 net acres in the undeveloped play area. In addition, we control approximately 125,000 net developed acres in the traditional fairway area of the basin.

Since beginning our drilling program in the Fayetteville Shale in 2004, we have drilled a total of 50 wells and participated in one outside operated well. The wells are located in eight separate pilot areas located in Franklin, Conway, Van Buren, Clayburn and Faulkner counties in Arkansas. In an east-west direction, we have drilled wells and established production approximately 40 miles apart, and in a north-south direction 15 miles apart. Of the 51 wells, 41 are producing. Six are in some stage of completion, or waiting on pipeline hookup. And four are shut-in due to marginal performance.

To date, we have drilled 9 horizontal wells in 4 separate pilot areas. Of the 9 horizontal wells 7 have been completed and 2 are waiting on completion. Since our last press release on June 28th, the Coon-234 horizontal well located in our Gravel Hill field was placed on production at approximately 1.7 million cubic feet per day. In addition, The Hall-112 horizontal well in our Brookie pilot area was production-tested last week at 2.8 million cubic feet per day, and the Black-217 horizontal well in our Scotland field tested at 2.9 million cubic feet per day.

The initial test rates for the completed horizontal wells has ranged from 1.4 to 3.7 million cubic feet per day, excluding our Vaughn 422 well, where we encountered well bore problems and had a limited stimulation treatment. Two of these wells, the Stobaugh 2-1 and McNew3 #2 which have been on production more than 30 days, have an average first-month production rate of 2.2 million cubic feet per day. Based on these production histories and our modeling work, we believe the average ultimate production of these horizontal wells will be between 1.3 to 2.7 Bcfe per well. We expect our year-end reserve assessment for our horizontal wells to be composed of both proved and probable reserves, as we have limited production histories for these wells.

Our first nine horizontal wells have on average taken 15 days to reach total depth, and our most recent well costs have been between 1.4 and 1.8 million per well, excluding non-reoccurring costs. In June of 2005 the Arkansas Oil and Gas Commission approved rules for our Gravel Hill and Scotland fields in our Fayetteville Shale play area, that provide for 560 feet minimum distance between completions, and common sources of supply, and up to maximum of 25 wells per section. To ensure adequate rig availability for our development plan here, we entered into a sales agreement in early July with a private company to build 5 new land rigs, capable of drilling both vertical and horizontal wells in the Fayetteville Shale.

These new rigs have design features that are optimal for drilling in our play. The first rig is expected to be completed in November, with one additional rig delivered per month after that. Our Fayetteville Shale activity in the third quarter will include drilling additional horizontal and vertical wells, some seismic acquisition, and testing of additional new areas of our acreage.

For all of 2005 we expect to drill 80 to 90 wells with our remaining 2005 program, with approximately 50 being horizontal. At the Ranger anticlines, as I have mentioned previously, we spuded 22 wells in the Ranger area in the first half of 2005, all of these wells are either productive or currently being tested. The Ranger anticline located in Yale and Logan counties Arkansas, produces from the [Boram] sands, between 5500 and 8500 feet.

Of the 22 wells, 15 are located in the core-producing area of the field. Four are located in the western expansion area we began developing last year. And 3 are in an eastern expansion area, nine miles from the proven productive part of the field. Three wells we drilled in the eastern expansion area penetrated pay in the Basham and Turner sands at about 3500 feet. We are currently obtaining rights of way and beginning construction of a pipeline to bring these wells on production. Additionally, we participated in an outside operated test, between the core area and this eastern expansion area, and this well penetrated the Boram sands, and is now being tested. Due to our continued success here we now plan to drill 50 wells in the Ranger anticline area for 2005, up from the original forecast of 43 wells.

Moving to East Texas, in the first half of 2005, we invested approximately $81.7 million. We continue to be pleased with the results of our development drilling program at our Overton Field located in Smith County Texas. In the first half of 2005 we spuded 36 wells at Overton, and have maintained our 100% success rate. We have now drilled 209 wells since we acquired the field in 2000. As mentioned earlier, our production at Overton is no longer being curtailed. Gross production is approximately 100 million cubic feet per day, up from the 80 to 90 million cubic feet per day during the curtailment.

In addition to our Overton Field we continue to be active in other areas in East Texas. At our Angelina River trend, we have acquired a total of 12,800 net undeveloped acres in four development areas, located primarily in southern [Nacadochous] county. To date in 2005 we drilled four wells in this trend, and two of which have production tested over 4 million cubic feet per day, and we expect to drill five more by the end of the year. We're hopeful this area will continue to grow for us, as well.

In summary, we are encouraged by our results at Overton and Ranger Anticline, and our Fayetteville Shale play. We are well on track to achieve the 13 to 16% organically-driven production growth for the year by continuing to invest in our high PVI projects.

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

Thank you, Richard, and good morning. As Harold indicated we reported strong results, primarily fueled by our production growth and higher realized commodity prices. Earnings for the quarter were a record 26.8 million or $0.36 per share up 29% from the second quarter of 2004. Cash flow provided by operating activities before changes in operating assets and liabilities set a new record for the second quarter at 65.1 million, up from 50.3 million for the prior-year period. The improved operating income over our exploration and production business drove our record results, as our natural gas distribution business generated a seasonal operating loss for the second quarter.

Operating income for our E&P segment was 48.6 million for the second quarter, up 30% from 37.5 million for the same period last year. Primarily due to the general increase in natural gas and crude oil commodity prices and the growth in our production volumes. We realized an average gas price of $5.71 per Mcf for the second quarter of 2005, up from $5.25 per Mcf for the same period last year. Our hedging activities decreased our average gas price realized during the quarter by $0.75 per Mcf compared to decrease of $0.57 per Mcf for the same period in 2004.

Disregarding the impact of hedges, the average price received for our gas production during the second quarter was approximately $0.27 lower than average NYMEX spot prices compared to approximately $0.17 lower in the second quarter of 2004. This change was due to widening locational market differentials that have occurred since the prior-year period. The Company currently estimates that its average realized market differentials for the third quarter of 2005 will range between $0.25 and $0.30 per Mcf.

We have approximately 75% of our targeted gas production hedged in 2005, and our current hedge position is detailed in our form 10-Q that we filed yesterday. Lease operating expenses per unit of production were $0.43 per Mcf in the second quarter of 2005, compared to $0.39 for the same period in 2004. The increase was due primarily to increased compression costs and higher oil field service costs.

Our general and administrative expenses per unit of production were $0.39 in the second quarter of 2005 compared to $0.35 in the second quarter of 2004. And that increase was primarily due to increased compensation associated with our increased staffing levels. Our full-cost pool amortization rate rose to $1.38 per MCF compared to $1.18 per MCF a year ago, primarily due to increase finding and development costs.

Currently we expect our full cost pool amortization rate to range between $1.40 and $1.45 per MCF equivalent for 2005. Our utility systems realized a seasonal operating loss of 2.4 million in the second quarter of 2005, compared to a loss of 1.4 million for the same period last year.

The decrease in operating income resulted primarily from higher operating costs and expenses. Operating income for our gas marketing activities was $900,000 during the second quarter, which was up slightly from the second quarter of 2004. Our capital investments for the first six months of 2005 totaled 186.7 million which included 181.5 million for our exploration and production business.

As we announced yesterday we have increased our capital program for 2005 from approximately $353 million to 438.8 million. Which includes a rig commitment that we announced earlier this month, and approximately 52 million primarily used to fund additional development drilling in our core operating areas. We are currently forecasting operating cash flow for 2005 of approximately 290 to 300 million, assuming that NYMEX gas prices were to average $7 per Mcf for the year.

We expect to fund the balance of our capital investment program from borrowings under our revolving credit facility, and/or proceeds from any debt or equity offerings we might pursue. We filed a new Shelf registration statement with the Securities and Exchange Commission yesterday, which will allow the Company to sell up to aggregate 600 million of debt securities or common stock. The new registration statement will replace a shelf that was filed approximately three years ago. The registration statement combined with our revolving credit facility, which currently has approximately 400 million of available capacity, will provide us with a great deal of flexibility in funding our capital program going forward.

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

Operator?

Thank you. [OPERATOR INSTRUCTIONS]

We'll pause for just a moment. Joe Allman, RBC Capital Markets.

Good morning, everybody.

Good morning.

I guess this is for Richard. Richard, could you comment on the Jackfork drilling you were doing in the Arkoma basin in Arkansas, and also the Rocky Mountain drilling if there is anything going on there? And any comments on any new ventures you've got beyond what we've talked about.

The followup is, in the Fayetteville Shale, beyond the five rigs that you're having built, any other plans to increase the rig count there, and can you describe those plans?

Okay. On our Jackfork play, you know, we have a pretty sizeable acreage block that we put together in Arkansas, and we've drilled one test well there, about an 11,000-foot well. We did encounter some--the short answer is we didn't find what we were after there, but we did encounter some sands in the Jackfork, and a little bit of pay in there, and so we're kind of encouraged it is a large structure. Looks like it may have some gas in the system but it will take some more drilling to prove up something commercial.

In the Rockies, the next thing in the queue there is our Round Mountain prospect and we think we'll spud that in August or September, and that is primarily a Madison test about 12,000 feet, and a good-looking prospect, it has about 50 BCF of potential.

You know, on other new things, we certainly are working on some new things. We have a team of people dedicated to that, and probably don't want to comment yet on that, because it's not a good time to be doing that, but we are currently working on new things.

For the rigs, for our Fayetteville Shale play, just to kind of reiterate, we have 3 running right now, and, you know, we're looking to add to that fleet as we go through the end of the year.

And then of course we have the 5 new ones coming. So you heard the schedule for that, the first one in November, and then one after that. So, you know, the ultimate amount that we were have for 2006 is kind of subject to our--the plan that we formalized which is not formalized yet, so I think we'll probably provide those details when we come out with our '06 plan, but we're pretty positive on what's happening out there.

All right, thank you.

Next we'll hear from Michael Bodino, Sterne, Agee & Leach

Michael Bodino. Couple quick questions to follow up. Joe hit a couple of them. Relative to the Ranger Anticline, could you expand your thoughts on how the inventory of locations has continued to grow there?

Sure, this is Richard, Mike. Well, I think, you know, if you think about what has happened there, development-wise and some of the more step-out tests, you know, between what we've done to the west, with the pretty big step-out, and what we've done here with this newer eastern area, which as I said in my comments is about nine miles away from [HPP] and we have a significant amount of acre rage there, you know, we're over 50,000 acres total in the play, and so I think those activities in the west and east are very encouraging for possibility of more drilling and then the spacing, the down spacing we're doing in the HPP area seems to be to be going okay. So we've talked about 130 to 140 other wells past our '05 plan, and these activities are, you know, very positive towards that, or maybe something better.

Okay.

Little bit additive to that, you recall we started drilling at the Ranger Anticline 6 years ago. It was an idea we had and went out and began tested. It was one of the seeds we planted then, and by the end of '04, we had drilled, I guess, about 45, 43, 44 wells there. This year we'll drill another 50. So we'll be setting at about 90. As Richard said, maybe there are another 130 or so that we could see. That number can vary a lot depending--totally dependent upon the results as we extend into the new areas. At this point it is looking better, not poorer.

Okay. My followup question relative to the Nacadochous county drilling, could you expand on the play. Is this Travis Peak or other horizons? Can you give more details on it?

This is Richard. Travis Peak and Cotton Valley, Mike, more of it I think is Travis Peak than Cotton Valley. But we have a nice block there. It is not a contiguous block of 13,000 acres, but, you know, it is a pretty solid piece of acreage there, and the drilling we've done is pretty encouraging. We had our [Rabely] well that really started that right at at the end of last year and it was about 4.4 million a day, and we have offset that with the well we call the [Isaaks], it's testing real well. Production holding up nicely, and couple other tests that are really designed to prove up the Travis Peak and Cotton Valley.

Thank you. I'll get back in the queue, thanks.

We'll hear from Ryan Zorn with Simmons & Company.

Good morning. I wonder if you can give us an idea you might go to field rules and when that might be in terms of hearings?

I believe our--this is Richard--Ryan, I believe our next hearing that will be for field rules will be in September. And I believe that's for our Brookie pilot area. Of course, we're in front of the oil and gas commission monthly for the integrations and other things.

Okay. And, Harold, did I here you correct, or maybe it was Richard that gave the stats 40 miles east and west and 15 miles north and south of Fayetteville, were those wells you have initiated, or where you've established those end points?

Well, those are--those are areas where we are either producing or have tested gas, so, you know, little bit of difference between testing and actually flowing in the pipeline. We would call it where we established production. And that does not include that geometry that we detailed there does not include wells a considerable distance to the west in our Fairway area, where we also have established production.

I guess for the eighth, or seventh and eighth pilots those would be inclusive in that area?

Well, there is one pilot that we're currently drilling on, that would be in the count of eight that would not be in those mileage figures.

In other words, the eighth one would be further extension.

Eighth one is about another 10-mile extension from those numbers.

Okay. So can you say which way east, west, north, south?

Yes, it's east.

Okay. Thanks. Appreciate it.

We'll now hear from Travis Anderson with Gilder Gagnon.

I wonder if you could tell us on the 41 horizontal wells you're planning to drill--

Travis, we can't hear you here.

Sorry. Is that better?

Yes.

Of the 41 wells you're planning to drill in the Fayetteville in the second half of the horizontal wells, how many of them are going to be in these seven or eight fields areas as opposed to new areas?

I think they will predominantly they will be in these one of these eight pilot areas that we've discussed. We start out new pilot areas with vertical wells.

Okay.

But I can't say for sure that we wouldn't be at the point where we're following up on new pilot areas late in the year with horizontal wells. The bulk of them would be in our existing pilots but we would be looking to opening up new pilots with vertical wells this year, and then maybe getting to a couple horizontals in those.

Okay. If all of these new rigs are additive, that implies that potentially on next year's plan you would be drilling north of 100 horizontal wells?

Well, the--talking about--

Crews and everything in time?

We have the three existing rigs and the five coming are eight rigs. We're not locked in that that is our plan, but, you know, I think our--we're heading towards being able to do a horizontal well, say, every 20 to 24 days, something like that. So you could kind of do the math on it. But we're not locked at those eight rigs.

Okay. Thank you.

Next we'll hear from Robert Christiansen with Buckingham Research.

Good morning. Couple questions, the Stobaugh well came on at 3.7, last update was 2.3, but that was back June 10th. What is the Stobaugh at right now, may I ask?

Oh, let's see, I think the current production on it is probably somewhere around 1.5 to 1.6 million a day.

The McNew, where is that at right now, the other one you've been on for 30 days?

Yeah, I don't have that in front of me.

The extended reach capability of the new rigs, the older rigs without top drives only get you out about 2,000 feet, as I under it. What is the extended reach capability of the equipment you've ordered?

Well, on paper the design says they'll do 4500 feet of lateral.

Thank you.

We like that ability.

Okay. I'll get back in the queue. Thank you.

We'll hear from Kevin Kelly from Hartwell.

Thank you so much for taking my call. You guys have shown some success in bringing down drilling costs in Fayetteville. What do you perceive to, I guess, going forward, is your ability to be to continue to drive down costs there? And I also wanted to get an understanding of your ability maybe to down-space within Fayetteville?

Well, this is Richard. If you look at the whole evolution of the drilling costs out there, and I think your question is focusing on the horizontals.

Yes.

We started out with a conservative design and had wells over 2 million, and then that has been coming down and, you know, our current AFEs if you look at them in the last couple wells were in the 1.4 and the 1.8 range. We're still doing some science out there, and we're still learning and certainly we would say that the equipment that we're using out there right now, we're not happy with the performance of it, and we think we could improve the costs pretty significantly just with better equipment. That's part of what the new rigs are for. And then there is just the learning curve on the design and performance ourselves. So, you know, I don't want to tell you long-term where we'll get that number to. I will tell you that we have a history of driving them down when we have high well count projects.

The caveat to that has to do with the pricing we're seeing in the rig market today. So for rigs we are contracting, that other people own, you know, we're faced with pressure, upward pressure, obviously, upward pressure and rig companies also wanting to term up equipment for longer periods of time, and in some cases the equipment's inferior equipment and the crews are not such a good thing. So that impacts our ability within that cycle as well. But engineering-wise I think we'll be making improvements and we hope these rigs we're buying which are designed for this kind of drilling, are going to give us efficiency in drilling also. Aside from drilling rigs, has to do with fracing stimulation, which is a big part of the cost. We're continuing to learn and try to make improvements, cost savings relative to the time that's required to carry on these multiple-stage frac jobs, and working with the vendors who provide that service, and we're making some progress there. So I think that's another area that we hope to improve in.

Great. Thank you. What do you see as your ability to down space within Fayetteville?

Well, the--you know, the data that we've put out there, and the modeling we've done and the performance of the wells and all those things rolled up, it is early in the play but we're kind of looking at that we should be able to do something like about eight horizontals within a 640. But that is preliminary. We have filed testimony that our vertical wells could be 20 acres or less, and that our horizontal wells are 45 to 60 acres. And then you have -- in the field rules where we have offset requirements between wells, all that has to be taken into account. But right now we're thinking 8 or 9 per 640, and that could change based on how we situate the wells, using multiple pads, or longer horizontals, and things like that.

And, as well, the performance of these wells. I think that everyone should be aware, as we mentioned in the comments earlier, that the longest well that we have on production that is a horizontal well, probably in the 40--what is it? The horizontal, the longest one we have on is 80 days now.

Right.

So we have 80 days' worth of production history on the first horizontal that we drilled. So this talk--discussions about spacing ultimately are discussions about what area does a well drain and what area a well drains is going to be dependent upon how the production curve looks and the cumulative production under that, relative to the gas in place. And so we don't have all the answers about that. So any answers we're giving and any testimony that we've made, in the Commission, is our best estimate, based on short production histories. I know a lot of black line in the sand, black and white kind of answer, but you all need to understand, that these are estimates, and there are uncertainties involved in it.

Thank you so much for your time.

You bet.

Next question will come from from Amir Arif with Friedman Billings.

Based on your recent vertical drilling you released over the last couple weeks seems to indicate you're starting to get some better rates as you go out east. I wonder if you are doing anything to try and capture that productivity on the horizontal yet, or are you waiting until the new horizontal rigs come in? In terms of larger fracs or longer lengths?

Well, the--this is Richard, Amir, I guess what you're alluding to is you seen some higher test rate verticals in the couple reporting periods -- I think we will see that throughout the play that there are some areas that are going to have higher deliverability, and when you talk about the total averages, for all of the verticals, and compared them to new higher-tested verticals, you know, you will recall that the Griffin Mountain area where we had the highest-- the greatest amount of verticals, probably not our best area, so that pulls the average down some and then when you contrast that with just the few higher-rate verticals, that's giving you the contrast there.

Yeah, what I was alluding to, high vertical rates you're seeing sort of indicates maybe potentially better reservoir characteristics, for instance, to flow rates. I was wondering if you're trying to capture that right now with horizontal wells, or whether you're just limited in terms of the horizontal length you can drill right now, because of the fracs that you're doing, or just not changing those factors?

Current rigs running out there are not a limiting factor in the context you put it. We're using--learning from both, and we're using the same kind of technology in fracing a vertical and a horizontal. The horizontal has a lot more stages of it. Certainly from the very earliest vertical wells to these we have refined our completion techniques.

Okay. I guess final followup question would be the rates, are you doing anything different on the horizontals? Let me put it that way. Are you--tell us what kind of thickness you're seeing out there. Has that been changing?

Is your question about doing anything different? You mean in regard to the frac job in horizontals versus verticals?

Get a sense of whether the reservoir characteristics are improving and whether it is the thickness or flow rates, and also are you doing anything to try to capture that? I mean, are you adjusting any of the parameters on the horizontal completion techniques right now?

Well, Amir, in general, within that what we have been calling unproven acreage which is some becoming proven, out to the East River we're doing most of the drilling, in the non-Fairway area. The gross thickness of the shale is similar, above 200 feet. Maybe all that isn't contributing, but in terms of the shale thickness, it's similar.

There is probably some difference in rock characteristics being that either some maybe some natural fracturing in areas. Many differences in mineralogy in some of those areas. Structural differences in Griffin Mountain area, where we really haven't had quite a good of wells is vaulted up more, than some of the other areas. So that could be a difference.

On the frac stimulations, as Richard said, the frac jobs we're doing on the horizontals are similar to the ones we're doing on the verticals, except we're doing multiple stages. In 2,000-foot lateral, we'll perforate, frac, set a plug, backup up the whole perforate frac, set a plug, and so we're doing multiple stimulations, but the mix of what we're pumping in there, is similar to what we're using in the vertical wells.

And then but are we making improvements and changes and trying to take advantage? Certainly. We're, you know, as we can get through the integrations that we're doing to be able to drill in areas where we've had good results we're drilling horizontal wells, where we're comfortable with understanding the geology. We're trying to exploit that and yes we're continuing to make changes in the frac design, and some of them might seem rather small, and I don't think this is the forum to get into the details of it.

But in how we perforate, how we break down, sand concentrations, a lot of that is our guys are very busy on it, and Schlumberger has been very helpful to us, and experimenting with things, and we think we're making progress there. Both in cost and maybe that is reflected ultimately in performance as well.

Sounds great. Thanks.

We'll now hear from [Lawrence Narpa, Passport Capital].

Good morning, gentlemen.

Good morning.

Just a quick question also related to the fracturing. I know that you all had used, you trialed slick water on your vertical wells. Have you done so yet on your horizontal wells, and more generally, are there any sort of non-nitrogen-based techniques that you think might still hold promise on your horizontals?

Well, we have not done anything but the foam, the foam fracture on the horizontals. At some point we need to go back and try a slick-water frac. Slick-water fracs generally would be less expensive. We only have done, I think, two slick-water fracs, kind of early on, on the vertical wells, and, you know, we're talking about that. I think, yes, we do need to do that and we will. I don't know when that would be scheduled but we've been talking internally about that.

Okay. Great. Thank you.

We'll now hear from Van Levy, [Wellman Rhode].

Good morning, gentlemen, how are you?

Good, how are are you.

Good morning.

I was hoping to understand the cost advantage from owning your own rigs, also you talked a lot of the service companies, talk about how difficult it is to get qualified and maintain qualified crews. Can you address this? I was also interested that it appears to take 5 or 6 months to build these things, so from my perspective it seems to have a, you know, pretty interesting impact on the service side, and what service companies can do to jack up rates. It seems like the E&P companies have a response if the rates get too far out of hand. Could you discuss this?

Well, it's very clear when you sit down and look at the economics or when you guys talk to the service sector on the drilling side, that current rates are--current day rates are in excess of replacement cost. And in addition to that, rigs are very tight, and the quality of what you get incrementally when you try to add rigs, both in the iron and in the quality of the crews, generally, is kind of marginal. In fact, in some cases unacceptable.

And so for a play like this and how we've viewed this, when we look at the economics of it, the economics themselves are compelling just based upon what if you could get the rigs you want, based upon the rig rates versus the cost of owning these things and operating them yourselves.

Now, realize that if you're going to do that, which we made a decision to do, then we're faced with some of the same issues that the drilling companies are, relative to crews, training crews, and all of that. We went through a pretty heavy-duty soul-searching before we decided -- before we made the decision that we made. The first driver in it is availability and the design of the rig that we need to do this type of activity. And so specifically what we're buying, we think is directly suitable to this.

We know that we're going to be faced with the same challenges relative to crews, and so on. But, what we can do is we have enough margin between the cost of operating that rig and and where current rig rates certainly are to share, and where current rig rates certainly are, to share that in motivational way with the crews that we have, and with our ability to recruit and maintain and manage a quality workforce. One of the things we have done in Southwestern Energy, we struggle sometimes, we work hard to make our decisions, but once we made them, we're going to work really hard to make it work. And that is what our commitment is regarding the rigs that we're buying here.

If you think about overall the driving force for our Company has been great present value of at least 1.3 or better per dollar invested in our business. And so if we're saving that increment between the cost to operate those rigs and where day rates are, that is a further enhancement to the economics of our project, and that is what has driven that decision.

That was kind of the thread of my question, also, is in the Barnett shale and some of the areas, some people talk about IP rates essentially equaling reserves so if you get 3 million a day well, translates into 3 BCF, you know, ultimate recovery. Your rates at [Deep I line] were 1.4 to 3.7 IP's on the horizontals, and the reserves you talk about are 1.3 to 1.7. It was interesting also when following Barnett, big company like EOG was pretty aggressive in outlining some, you know, reserve upside, significant reserve upside.

I guess what I'm asking is with the cost advantage you have in the rigs and if there is some conservatism in the way you cast the reserves to date, you had given some numbers earlier, I think, on gas prices and rates of returns. Have those changed as you are getting more results. Are you feeling the bias of those numbers moving up or down or are they still at the same level that you last released?

The first thing I guess is going to line us back to what I said a few minutes ago. We have 80 days production on the oldest horizontal well.

Right.

And then the other thing, just to clarify this, since you used the term 'Reserves.' I think most of what we put out has things like, estimated ultimate recoveries, which are easy to translate over into the word reserves. We all need to understand, also, that in today's world, reserves have a certain set of characteristics, and they must meet hurdles and criteria they must meet to be called reserves.

When we talk about estimated ultimate recoveries that is our best guess at what we think something is going to produce, with the data we have. Again, the horizontal wells, oldest ones 80 days. So we're using that in that terminology.

Only reason I bring up reserves versus ultimate recoveries, there may be a difference in what we can actually and do book in reserves. Difference between with what we think the ultimate recoveries might be, and the actual reserve bookings, and that has to do with the certainty at a given point in time. It might be important in understanding how we talk about this. Now, there are also one could call some of amount of whatever you might think the ultimate recovery might be, you call that probables.

Our numbers that we put out to this point on estimated ultimate recoveries are our best-guess estimate of what these wells will produce. And, you know, within 80 days that won't change a lot. The early declines on these things are pretty steep, and the real open question is when will they flatten, or will they flatten, or do they flatten at all?

Okay. Okay. So the numbers that are out there are still your best--your best guess, educated guess at this juncture? .

That's right.

Okay. Great. Thanks, Harold.

We'll take a follow-up from Joe Allman.

Hi, everybody. In terms of the development of the Fayetteville Shale, I'm trying to get my arms around what you folks are thinking about say beyond 2005, in terms of number of rigs you might have, working at the peak of the development of this play? And also what might some other constraints be, pipeline capacity, just people constraints. Can you kind of help us go through what you're thinking about in terms of the development of this play?

Yeah, I think that we're not prepared today to talk about the ultimate program as Richard mentioned earlier. We do our planning cycle really heavy-duty planning cycle is we're getting into it right now. So in particularly the question about the peak, you know, the peak--let's just think in a bigger picture, a broad picture about this whole thing. 690,000 acres, plus another whatever, the real question here is--two real questions here, one is, you know, we planted a seed here a long time ago, and now you can think of 8 pilots as seedlings that we're watering, and the real question is, how large and just visualize this, annual report had a seedling and a great big tree behind it.

The question is, how big is that seedling going to grow? As an individual tree. And the second question is how large is the forest? And we don't know the answer to how large the forest is, and we have tested it now over pretty big area, and we have a short production history on each individual horizontal well.

The ultimate number of rigs that are going to run out here, the peak question is dependent upon how big the forest is and what the economics and ultimate reserves are for each one of those horizontals. So the peak number of rigs could be a lot of rigs. You know, I mean, it is just obvious because of the acreage position and doing the math.

I think probably your question is when you get tight around what '06 is going to look like, and we had an earlier question there, if we have, you know, 8 rigs up and running at the beginning of the year, then you can sort of go through math. I haven't done it in in my head but you get a lot more wells than we drilled this year. It could be double that number. That is probably as far as I want to go today in trying to answer that.

Appreciate that. And over to the Ranger anticline, you had some good test rates on recent wells and how do those compare to previous wells? Are they better than what you've been doing before? Similar? I know there has been some variability amongst the recent wells, too.

And also the 130 or so contingent wells you've got beyond this year, what's included in that? I know you touched on that. Is there a lot of, say, eastern development included in that 130 or so. Is it a lot of western? Can you describe that for us?

Well, the--we see a lot of variability in the test rates out there and, you know, what we've seen the first half of this year is not out of the--out of the boundaries of what we normally see. So I think we're kind of doing our average well out there. Late last year we had some real high rate wells moving to the west, and I think we'll see some more variability there.

Our base average well, though, is providing real good economics, so in terms of the contingent locations, certainly they would involve acreage, you know, to get to those kind of numbers, proving up acreage as we have been to the west, and then this eastern expansion is kind of a newer thing, and I think that's where maybe some of the upside would be.

I think I want to do come back to your question. I don't think I went as far in answering that as probably part of your question, and that is, you know, what will be the critical elements that might be roadblocks to the ultimate plan, and, you know, I mean, if you think of this as an academic question, a business is a unit that does a transformation of some inputs to some outputs, and, you know, our output is gas, and our input is ideas and, you know, and that requires rigs. It requires resources, which means, rigs, vendors, capital, people, and all of those things.

And this project, by the nature of it, is going to change every day. I mean, its size has the potential of changing everyday, and so we are going to need to react to that. And I think we will have a different constraint at different points in time. One clear restraint we had is we couldn't see the ability to go in the market and find drilling rigs that we needed to use and wanted to use to do this work. So we've taken a step to, you know, to deal with that, and in the last eight months we hired 65 people here, and we're still recruiting people. So the people resource is also, you have to keep that matched up. And then the capital resource is another element of it.

So all of those things we have our eye on the ball, and we're working hard to manage them and bring them up. But I think at any given point in time one or the other is going to be--one or the other of those inputs is going to be a constraint if you had to put your finger on it. Your take-away capacity. You probably noticed that we recruited an experienced high quality guy, [Gene Hammonds], announced that recently and formed Southwestern Energy Midstream Company, which he'll be heading up our marketing operation, and our DeSoto gas gathering project.

Lot of alternatives there. We don't have a constraint on gas moving out of here now, but there's a chance that could happen one day. We want to to be prepared on all the fronts.

Got you. Quickly on the CapEx increase, how much of that deals with cost inflation?

There is a piece of that especially where we're drilling lots of wells, but I think of the if you take the 50 million piece that does not include the rigs, maybe about 10% of that we would allocate towards rising costs, kind of on a well basis.

Got you. All right. Thank you, guys.

Thank you.

We'll now take a follow-up from Ryan Zorn.

Yes, thanks. Harold and Greg, on the shelf, I know you get some term debt to probably refinance here in December. But also notice that the shelf just says either debt or equity. And no converts or anything like that named. Is that intentional or how are you thinking about future financing?

Oh, well the shelf actually covers debt, convertibles and equity. Though it's in there for all those kind of things. But our current shelf is almost three years old now, so it's stale really by industry standards, and we had 190 million of remaining capacity, and 125 million of public debt that matures this December. So the shelf filing really combined with our revolving with our credit capacity which on our revolver right now, we have 400 million of additional capacity. When you take those things combined it just gives us a great deal of flexibility in funding our capital program as we go forward.

I think the key point is as all this goes through our process here and firming up our plan for '06, you know, capital is one piece of that.

Okay. Any change to your historical thinking on optimal debt to cap levels? Given the evolution of the Fayetteville?

I mean, that's a moving target, too. It really is a function of the same point that Harold has, is what is our plan going to look like over the next few years, and as we've indicated we do expect our program to be increasing next year in our drilling in the shale, and when we get that plan really developed, it will help drive, you know, what that capital structure should be going forward.

Okay. Appreciate it, guys.

We'll now hear from Robert Christiansen.

Yes, coming back to constraints. The pressure pumping business you're using Schlumberger, and just, you think, with the commitment to the rigs and all the future holds, is it a build it and they will come, for Schlumberger to expand, or perhaps draw other pressure-pumping companies into the play? Is that your strategy? That's point one.

Point two, if it is not a build it and they will come, are you offering any inducements to Schlumberger or others to get involved in it, and I guess a third would be, you know, maybe you ought to enter the pressure-pumping business. You know, if you entered the rig business, why not the pressure-pumping business. It is a three-part question. Just update us on the expansion possibilities for that bottleneck? Thanks.

I think for the pumping services stimulation, cementing, that kind of package of services that we need, you know, the strategy is definitely not, start drilling lots of wells and hope they come, because we have much bigger plans than that. We have engaged folks that are providing those services right from the beginning, and sharing with them where we're trying to get to, and we have vendors that are making significant capital commitments right now to kind of be in lock-step with us, related to those services. So, no, we can't--we can't just build the rigs and hope the other stuff happens, Bob.

We're working it all simultaneously. When you look at the--certainly we are looking at the whole picture and Harold has encouraged us to look at the whole supply chain and value chain, if you will, on this thing, and we are kind of stepping out of the box and looking at that whole thing. When you have the potential for the number of wells and the years of a program that we hope this will be, I think it is smart to do that. When you are needing goods and services that are highly repeatable it is smart to do that. We're looking at that whole picture in terms of supply and service. Pumping service is probably one of the harder ones and maybe not the wiser ones to do that with. But there are a lot of other things in that chain that we are looking at.

Again on capacity, when you bought the five drilling rigs, in that contract was there an option, any money towards an option to buy more from that supplier?

Yes, there is.

Any sort of preferential right to move yourself up in the queue in terms of I don't know what their manufacturing capacity is, anything along those lines?

Well, I just would stop it there. We got a firm contract, the rigs are going to come, we think as we laid out the schedule, and we do have an option to do some other things.

Okay. And then I'd like to ask a Ranger question. You had a little red dot on the map to the south, you know, looked like a little mile to the south. Was that well drilled sort of the middle of all of your activity you were going to step a little further south? Have you drilled that well?

No, we've not drilled that well, yet, it is designated as a well for this year. We've drilled a-- the outside operated well we talked about, between the HPV area and eastern expansion would be in our block of acreage kind of half-way between those areas.

I see. Shifting around to Fayetteville, you had a well that was permitted, looked to me about 12 miles further east of the Steed well which was about a 14-mile step-out, Carter well, has that been drilled?

It is drilling right now.

Beautiful. I just wanted to--I don't know that I wrote it down.

How many questions are you going to ask here, Bob?

I don't know. Maybe I'm last in queue.

Okay.

I can get off and give it to others. One more. Clarification of the Stobaugh. Started out life at 3.7. 30-day update was 2.3, and you said what is it flowing at right now? I'm trying get a sense, is the rate of decline slowing? I think you said 1.5 but I want to be more clear on it.

Yes, yesterday's rate was 1.5 million cubic feet per day.

Okay. Thank you.

And let me just, while we're talking about those wells, the one that was the eastern one I think you were trying to pin down there, Bob, is actually the Martin.

Oh, it's the Martin.

You said the Carter.

I may have labeled it wrong on my map. Okay. Well, thank you, guys. Appreciate it. Bye-bye.

And there appear to be no further questions at this time.

Well, thank you can for joining us today and asking all the good questions and that concludes our teleconference.