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Southwestern Energy Company (NYSE:SWN)

Q1 2008 Earnings Call

April 25, 2008 10:00 am ET

Executives

Harold M. Korell – President, Chief Executive Officer

Greg D. Kerley – Executive Vice President, Chief Financial Officer

Richard F. Lane – Executive Vice President

Analysts

Gil Yang – Citigroup Global Markets, Inc.

Amir Arif, CFA – Friedman, Billings, Ramsey & Co.

Brian Singer – Goldman Sachs

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Jeff Hayden – Pritchard Capital Partners

Scott Hanold – RBC Capital Markets

Thomas Gardner – Simmons & Company International

Mike Scialla – Thomas Weisel Partners

David Heikkinen – Tudor, Pickering & Co.

Operator

Good day, everyone, and welcome to the Southwestern Energy Company’s first quarter earnings teleconference. At this time I would like to turn the conference over to the President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold M. Korell

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 you have not received a copy of the press release we announced yesterday regarding our first quarter results you can call 281-618-4847 to have a copy faxed to you.

Also, I’d like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainty affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. 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, we’ve had a very good start to 2008, as you can see in our first quarter results. Our progress in the Fayetteville Shale continues to improve resulting in strong growth in our production volumes, which were up dramatically over last year. This growth is primarily fuelled by the Fayetteville Shale where our gross operated production recently reached approximately 400 million cubic feet per day, up from approximately 155 million cubic feet per day a year ago.

We also have begun to see the impact of our James Lime activity in East Texas and as a result of these efforts we have moved our second quarter production guidance up by around 15% compared to our previous estimate. Overall, I’m very pleased with our results and we look forward to further guidance for the third and fourth quarter after completing the reassessment of our 2008 asset sales and capital investment plans.

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, and then we’ll answer questions.

Richard F. Lane

Thanks, Harold. Good morning. During the first quarter we produced 39.1 BCFE, up 71% from the first quarter last year. Our Fayetteville Shale production was 23.6 BCF, up significantly from the 8.2 we produced in the first quarter of 2007. Production from East Texas was 8.1 BCFE, 5.9 from our conventional Arkoma properties, and 1.5 from our Permian and Gulf Coast. As a result of our strong first quarter performance we now estimate that our second quarter production will range between 41.5 and 42.5 BCFE.

In the first quarter we invested approximately $377 million in our exploration and production business activities and participated in drilling 169 wells. Of the $377 million invested approximately 84% was for drilling wells.

In the Fayetteville Shale in the first quarter we invested approximately $285 million, including $237 million to spud 122 wells. As Harold said, at April 14th our gross operating production rate here was approximately 400 million cubic feet per day, up from approximately 155 million cubic feet per day a year ago.

During the first quarter of 2008 our typical well had an average completed well cost of $2.9 million, an average lateral length of 3,285 feet, and an average time to drill of 15 days from re-entry to re-entry.

As of March 31st we had drilled and completed 142 wells with lateral lengths over 3,000 feet. We forecast that the average gross ultimate recovery from wells with greater than 3,000 feet horizontal laterals will range from 2 to 2.5 BCF per well with an average completed well cost of approximately $3 million. As expected, we are continuing to see improved results as we are drilling our wells with longer laterals and completing them more effectively.

In late 2007 we began a project to demonstrate the benefits of a full scale development strategy in a four-section area of our southeast Rainbow pilot area in Conway County. Through the middle of April we have spud 22 wells in the area, 21 of which have been drilled to total depth. Based on the limited production histories of the 10 wells that are already on production, we’re seeing improved initial production rates, shorter drill times, and lower costs than the offsetting wells. We expect all the 22 wells will be fracture stimulated and on production by the end of the second quarter.

Results from the pilot area are already beginning to provide potential improvements for the play’s full scale development, including using multi-well pads to reduce loss in our service impact and concentrating operations to improve overall efficiency.

In some new ventures activity in Pennsylvania we currently have approximately 100,000 net undeveloped acres where we believe the Marcellus Shale is prospective. We are currently analyzing core on our first vertical well here and drilling our second.

In our conventional Arkoma activities in the first quarter we invested approximately $36 million. We participated in drilling 26 wells here, including 15 at our Ranger Anticline field and five at our Midway field. Our production from the conventional Arkoma in the first quarter was 5.9 BCF, up from 5.5 in 2007.

In East Texas in the first quarter we invested approximately $52 million and participated in 14 wells. Production from East Texas was 8.1 BCF in the first quarter, up from 7.6 in the same period in 2007.

We continue to be excited about the developing James Lime play where we have a significant acreage position. Through the end of the first quarter we had four operated James Lime wells on production. The gross initial production rate from these four wells ranged from 5 million to 14.4 million cubic feet per day. We’re also currently testing our fifth operated well here. Our current net production from the James Lime is approximately 12 million cubic feet per day, including production from some outside operated wells. Due to our recent success in the James Lime we now plan to participate in approximately 21 net wells in 2008 and this is up significantly from our original 2008 plan which called for 10 net wells.

In summary, we had an outstanding quarter in our E&P business and are looking forward to continued strong results in the remainder of 2008, including meeting or exceeding our PVI target, achieving significant production growth, and significant increases in proved reserves.

I’ll now turn it over to Mr. Kerley, who will discuss our financial results.

Greg D. Kerley

Thank you, Richard, and good morning. The significant growth in our production volumes grew record earnings in the first quarter of $109 million or $0.31 a share, more than double the prior-year period.

Our operating cash flow also increased significantly to $283.7 million, up almost 100% from the prior year.

Operating income for our E&P segment was $165.7 million during the quarter, up from $74.3 million in the same period a year ago.

We produced 39.1 BCF in the first quarter, up 71% from a year ago, and realized an average gas price of $7.70 per MCF. Our commodity hedging program increased our average gas price during the quarter by $0.24 an MCF.

Our leased operating expenses per unit of production was $0.77 per MCF equivalent in the first quarter, up from $0.74 a year ago. The increase is primarily due to increased production from our Fayetteville Shale play, which has higher per-unit operating costs in our other focus areas.

General and administrative expenses per unit of production were $0.42 per MCF in the first quarter, down from $0.47 last year. The decrease is primarily due to the effects of our increased production volumes which more than offset increased payroll and related costs associated with the expansion of our E&P operations.

Taxes other than income taxes were $0.16 per MCF in the first quarter, down from $0.27 in the prior year due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and accrued severance tax refunds related to our East Texas production.

Our full cost pool amortization rate averaged $2.30 per MCF in the first quarter compared to $2.24 a year ago.

Operating income from our Midstream Services segment was $10.2 million during the first quarter compared to break even a year ago. The increase was due to higher gathering revenues related to our Fayetteville Shale play partially offset by increased operating costs and expenses. We are currently gathering about 470 million cubic feet of gas a day in the Fayetteville Shale play area through approximately 634 miles of gathering lines.

Operating income for our utility was $11.6 million in the first quarter, up from $9.4 million in the prior year. The increase in operating income was due to colder weather along with the implementation of a rate increase which became effective August 1, 2007.

We’ve been working for the past several months on improving our liquidity and strengthening our balance sheet, as well as positioning Southwestern for future growth. In November of last year we signed a stock sale and purchase agreement for the sale of our utilities subsidiary for $224 million plus working capital. The sale is subject to certain closing conditions and regulatory approvals and is expected to close around mid-year.

In April we announced the sale of a portion of our Fayetteville Shale acreage for approximately $520 million and we are currently marketing our Permian Basin and Gulf Coast E&P assets.

At March 31st, 2008, we had total debt outstanding of approximately $1.1 billion resulting in a capital structure of 41% debt and 59% equity. The combination of our strong production growth, higher realized commodity prices, and planned asset sales is expected to significantly improve our balance sheet and, as a result, our total debt could decline to 25% to 30% by year end.

As you’ve heard from our comments today, we’re off to a great start in 2008. That concludes my comments and I will turn it back to the operator to explain the procedure for asking questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). Also, we ask that you please limit your questions to one question and one follow up to allow everyone a chance to ask a question. After your question has been answered you may re-signal. (Operator Instructions).

We’ll take our first question with Brian Singer with Goldman Sachs. Please go ahead, Sir.

Brian Singer – Goldman Sachs

Thank you. Good morning. Could you talk a little bit more about the Southeast Rainbow pilot with the rates that you’ve seen and the costs that have come down to about $2.6 million? Where do you think you are in that process? What are your expectations for the remaining wells in terms of where you think you can take costs? And what conclusion do you take for your large area urgency move (sic) towards more pilots within your Fayetteville position?

Richard F. Lane

Well, Brian, we were really encouraged by what we’re seeing there. I think you can tell by the numbers of wells that we’ve talked about that we’re really just getting going in that kind of mode. I think it’s important to recognize that regionally in the play the costs are going to vary because of depths and other things like that. We almost have to look at not so much the absolute costs right there but the kind of savings that we think we can achieve per well. That should be able to be duplicated in other areas. We’re seeing somewhere around $200,000 worth of potential savings from that focused activity for some of the reasons we talked about in our release and that’s real encouraging. We’ll try to expand that footprint this year and verify it some more and try to go into that mode for most of what we do eventually.

Brian Singer – Goldman Sachs

Do you see further potential for cost decreases or do you think $2.6 million is a good number going forward?

Richard F. Lane

Well, $2.6 million is specific to that area was my first point, so I wouldn’t carry that across the entire play. I think the net difference that we’re seeing is probably the repeatable. Hopefully the repeatable savings.

Harold M. Korell

Two things, Brian, that affect that maybe more clearly stated is that where we are drilling, where the play is deeper and where we have drill deeper, the costs will likely be $2.6 million per well. Of course, the other thing that can affect this entirely is what happens to service costs as time goes on. There may be some areas of the play where we can’t set up and drill these nice geometric north-south patterns due to structural complexities that could exist there. That’s just not saying we won’t or we should concur savings as we’re able to do pad drilling and do a full development type scenario, but there are a lot of factors that come into play. This is a very broad area that we’re drilling across and I don’t think it’s possible for us to say exactly what those costs parameters are going to be across the whole thing.

Richard F. Lane

Yeah, I would also say, Harold, that we’re still experimenting with our completion methodology there and trying some things that have some promise to be an economically positive impact but may cost more per well.

I think the thing to focus on is the efficiencies we might get that we can duplicate across the area.

Brian Singer – Goldman Sachs

Thank you.

Operator

Thank you. We’ll take our next question with Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Thanks. Good morning. When you guys obviously look at your 2008 production I guess you didn’t sort of update what your expectations are. Is there anything generally we should sort of look at as far as what your capacity looks like and kind of give us a sense of if there are anything constraint in the system we need to be aware of and what’s sort of the update on the Boardwalk Pipeline from your perspective?

Richard F. Lane

Well, the Boardwalk Pipeline at this point is on schedule. We’re still expecting it, at least the first leg of it, to be in service sometime before the end of the year, which would take us over to the east part of the current markets that we service now, but just increased capacity there. As far as constraints right now, we’re building gathering line and adding compression to keep up with the field activity. So there’s not delays and type orders or delays in compression being received or anything like that at this point.

Scott Hanold – RBC Capital Markets

Okay. Very good. And as far as your capital budget, I guess the first quarter you spent a little bit more. If you sort of extrapolate that across the year versus where your original budget is can you give us a sense of how much that could go up versus what your current budget’s at?

Richard F. Lane

Well, one of the things that, as Harold indicated in his early comments, we’re currently looking at or revisiting our plan and how it will be affected by our asset sales. Also by the improvements that we’ve seen from the well results. Those things combined will really drive what we think capital for the rest of the year will be. We’re not ready yet to issue new guidance there. We’ve still got some work to do to develop that.

Scott Hanold – RBC Capital Markets

Appreciate it. Thank you.

Operator

We’ll take our next question with Amir Arif with FBR Capital Markets. Please go ahead.

Amir Arif, CFA – Friedman, Billings, Ramsey & Co.

Morning, guys. Just a question also on the multi-well pad rolling that you’re doing. You talked about cost and the savings synergies. Can you talk a little bit more about the federal rates your getting out of these wells and whether that’s just due to the lateral lengths or it’s just due to better optimization of the fracs or what do you think is driving that?

Richard F. Lane

I think it’s both of those, Amir. When we look at the offset wells, we’re trying to pull the best analogy to the new activity. So we have an average lateral length that’s a little higher and then we have the benefit of our newest thinking on completions. So I think it’s both of those things.

Harold M. Korell

Yeah, from the beginning of this play we’ve talked about the name of the game being to get in touch with the most rock you can for the dollar invested. And that’s what we continue to work towards. That means working towards improving the fracture stimulation. It means longer laterals, doing the best frac treatment that you can, which could mean a lot of technical things some of which we believe we’re getting some additional breakthroughs in regard to the completion itself. Of course, longer laterals. And work towards continuing to decrease the cost.

As Richard mentioned earlier, some of the things we’re doing actually increase the cost, but if they increase the output more dramatically than the cost is increased then PVI goes up and we’re about PVI.

Amir Arif, CFA – Friedman, Billings, Ramsey & Co.

Sounds good. And then just in follow up, in terms of the spacings down about 100 acres. Are you seeing any kind of communication or do you feel that you can even take that you can even take that spacing lower?

Richard F. Lane

Yeah, I think we’re not seeing interference, is the answer to the question. We’re hopeful we can go lower than that. In my gut that doesn’t seem like where we’ll end up and the well results confirm that so far.

Amir Arif, CFA – Friedman, Billings, Ramsey & Co.

Final follow up question just on the lateral lengths. How far do you want to push those lengths in terms of the formation you have and the rate capacities you have?

Richard F. Lane

Well, I think the rate capacity will do pretty much all we want to do. In those average numbers that we’re publishing we have some less than the average and some more than the average. We have a really pretty good number of wells that we’ve gone down to 4,000 feet. We’ve done those fairly well without a lot of well problems. We’re moving in that direction.

Amir Arif, CFA – Friedman, Billings, Ramsey & Co.

Sounds great. Congratulations on the good results.

Operator

We’ll take our next question with Gil Yang with Citi. Please go ahead.

Gil Yang – Citigroup Global Markets, Inc.

Good morning, everyone. Richard, if you look at your operations in the quarter could you maybe just break down the overall sequential change in the well performance? Can you just sort of break that down into the different drivers of the various components that contributed to the better performance?

Richard F. Lane

Sure. I think the average lateral length, if you look at our table there in our release materials you’re seeing the average lateral length going up and the increased rate, IP rates, 30-day and 60-day rates going up commensurate with that. So there’s obvious correlation there. And then the improved completion techniques. We’re doing some new things on how we perforate and the spacing of perforations which we think is having an impact. I think it’s all those things, Gil. It’s also, you know, hopefully we’re getting smarter about this every month that we attack it. We’re doing a better job I think on the geosciences and using the 3D seismic that’s having a nice impact for us. So I think it’s collectively all those things. Our team’s doing a great job on it.

Gil Yang – Citigroup Global Markets, Inc.

Thanks. As I look at the lateral length increase it’s relatively minor compared to the volume IP increase. So is there a mixed effect where you’re drilling wells in better areas and fewer wells in poor areas? Is that a component as well? Can you quantify between those different factors how much is coming from each?

Richard F. Lane

I can’t quantify it exactly, Gil. I’d have to have lot of data in front of me to do that. It depends how far you’re looking back. If you look back several quarters I think we’re, as we’ve said, our 2008 plan would be less exploratory in nature and be more in where we’re more certain about what’s happening and know how to best complete the wells more in a development mode. I think you’re seeing some of the effect of that.

Gil Yang – Citigroup Global Markets, Inc.

Okay. And just sort of the last question in follow up regarding that. Was the first quarter already at that full development mode stage or do you still need to transition into that development mentality more through the year?

Richard F. Lane

Oh, yeah, definitely. We definitely need to transition into it. And we’ve highlighted some areas that we would take that footprint that would be considerably bigger than the first one. That would be logical progression of that activity. We’re starting to prepare the things that have to happen before the rigs show up to do that.

Gil Yang – Citigroup Global Markets, Inc.

All right. Thanks a lot.

Operator

We’ll take our next question with Tom Gardner with Simmons and Company. Please go ahead.

Thomas Gardner – Simmons & Company International

Morning, guys. Most of your drilling in the first quarter was in areas where you had 3D seismic coverage. Are there portions of your acreage that are condemned by this or that you would not drill? And then in what specific ways are you using this seismic to high grade?

Richard F. Lane

I wouldn’t say there’s, there are not broad areas that we have condemned using the 3D seismic. It’s more a section by section kind of look, Tom, that before we drill the wells we’ve got a detailed mapping where that well path is going and trying to watch for faults and other complicating things. It’s more of a high grading well by well, not so much broadly across the whole play.

I will say there’s some things we’re doing with the seismic data that goes beyond just using the reflection data to map structure and faults and things. Some other derivatives from the seismic data that we are starting to correlate with productivity. That’s another benefit that we’re starting to see. We need some more data on that to make sure that correlation holds up. We’re also probably not going to talk a lot about that as we go forward here.

Thomas Gardner – Simmons & Company International

I understand. And just as a follow up to a previous question on spacing, are you doing micro-seismic work or (inaudible) modeling and what distance away from the lateral is that suggesting you’re going to try and effectively?

Richard F. Lane

We are doing micro-seismic work. We’ve done several and we continue to do them. Really great tool. Sometimes the data is hard to interpret, but we think we are seeing where the fracs are going in a general sense. The half lengths we’re seeing there are somewhere on the order of 500 feet. Again, that’s not consistent to every stage or every well, but it’s helping us understand what’s happening when we frac these wells and gives us the insight you’re talking about there to how close maybe we can get.

Thomas Gardner – Simmons & Company International

Great. Thanks, guys.

Operator

We’ll take our next question with Joe Allman with J. P. Morgan. Please go ahead.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Thank you. Good morning, everybody. Could you give us your plan for ramping up the rate count in the Fayetteville Shale? Could you also talk about ramping up the rate count elsewhere outside the Fayetteville and how you’re thinking about that and what the constraints are?

Harold M. Korell

Well, we don’t have a plan to talk about other than what we have already talked about in regard to the Fayetteville. We have 19 rigs drilling there and we haven’t modified that. I’d say at this point in time we’ve been focused on getting and keeping our helicopter balanced, I would say. With Fayetteville we have lots of opportunities. We’re building our workforce to be able to see a day when maybe we can accelerate and also keep our capital in balance and watch our balance sheet. So we don’t really have anything new to report on that.

I think we did put in the press release, Joe, and Richard might have mentioned that we’ll be drilling more wells in the James Lime as part of our current plan this year and that’s primarily through shifting capital from some other project areas. Not the Fayetteville, but from some other project areas into the James Lime.

As we go forward, as Greg mentioned, we’re in a process here of re-looking at our year. There are quite a few moving parts right now that aren’t settled enough for us to be able to tell you any more than we have, I think, in our press release, which would be giving you an idea of where we think we’ll be in the second quarter.

We have pending the sale of the acreage in the Fayetteville Shale, which is moving in a closing direction. We still have pending the closing of the utility, which is moving in a closing direction. And we have thus far sold in a verbal auction some of our Permian Basin properties and are moving through a sale process for the bigger part of that. So we need to get clearly through those and then we can look at overall impacts on production, cash flow, where we would stand debt wise, and sometime later this year we’ll talk about that with you. But we can’t do it until we’re done.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

(Inaudible). And then the follow up is, what are you seeing in the Fayetteville and outside the Fayetteville in terms of the most recent trends for drilling and completion costs and just all service costs?

Harold M. Korell

Oh, you mean overall cost factors?

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Yes. What’s your view on it?

Harold M. Korell

Well, you saw the average for the quarter is $2.9 million. A lot of moving parts there, Joe. We have efficiencies going on in how quick it takes us to drill the wells. We talked about this re-entry time and it’s kind of a key time. As you know, maybe everybody doesn’t know, we talk about that time because we’re using the sputter rig. That’s the date we’re keeping track of there. But we’re doing better there so that’s affecting it positively.

Generally on service costs the big items would be the drilling and the pumping services. You know how we’re positioned on the drilling side by virtue of operating our own rigs and that margin’s still holding up nicely for us. It’s a savings net to swim. We’re seeing still good discounts on the pumping service side of things for cementing and stimulating and all that. Some pressure on steel costs. It looks like upward this year that will offset some of that. Those are the main factors.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Gotcha. Okay. Very helpful. Thank you.

Operator

We’ll take our next question with David Heikkinen with Tudor, Pickering. Please go ahead.

David Heikkinen – Tudor, Pickering & Co.

Good morning. Just one question in the Fayetteville around percentage of your acreage that you think will be developed over time. What are you thinking there now?

Harold M. Korell

Well, I don’t think we have gotten to that number.

David Heikkinen – Tudor, Pickering & Co.

How much have you appraised maybe is another way to describe it. If you drew a circle around where you’ve drilled what percentage of acreage have you filled around?

Harold M. Korell

Well, it’s hard. It depends on how big you draw the circle, David. We’re not trying to avoid the question. I don’t think I know how to answer the question. Probably still the best reference is to look at our map in our IR book that shows where the acreage is and it’s all within that brown. You can see where we drilled the pilots and we continue to drill more pilots and fill in. Then other companies are drilling intensely far over to the east, which was our last part of the buy area for us initially. Some are drilling north of our acreage. It just depends, I guess, on how big a circle you draw around these pilot.

David Heikkinen – Tudor, Pickering & Co.

Okay. Thinking about the outside operated well count, how many wells do you think you participate in further to the east and further to the north, or even in your core, that will be outside operated now, Harold?

Harold M. Korell

I don’t know how to answer. Richard, do you know? With the sale of the property over to the southeast to XTO some of our outside operators will be going away because some of that acreage is operated by Chesapeake. And Petrohawk has expanded its position. Do you have any idea?

Richard F. Lane

That is affecting the overall count of non-op wells. That’s a good point, Harold, because we were getting a lot of the proposals out of that area. But I think we’re going to be somewhere probably, if I had to guess, between 75 wells that we would have for non-operated. Everybody doesn’t give us their full-year plan.

Harold M. Korell

And when they do it changes. It depends on how aggressive some of the companies are going to be in there. They seem to be gearing up.

David Heikkinen – Tudor, Pickering & Co.

Yeah, very. We’re seeing that increase across the other operators. And then access to things like sand and water, overall services access as you’re expanding your development areas. Can you talk some about that? And that’s my last question.

Harold M. Korell

Yeah, I feel real comfortable where we are there, David, at this level of activity and at higher level activities. The resources seem to be there to do what we need to do. Water wise we almost have too much water right now. We’ve had a real rainy season up there in the Arkoma Basin. From a standpoint of retention ponds and other types of water sources we’re kind of overflowing there, which is a good thing. It’s made it hard to get around and operate for wet conditions. We have our water team dedicated to that that we’ve talked about and they’re doing a great job on that and staying ahead of our needs there on the completed wells. We’re in good shape there.

We don’t see any lags in profit to complete our wells. We’re looking at some new things there that maybe could help save on costs there. So we’re in good shape there. And the overall service industry is building around the play and causing more competition and better pricing.

David Heikkinen – Tudor, Pickering & Co.

Just one final question. Greg, on your technique order guidance, that includes the expected sale already. Just confirm that.

Greg D. Kerley

The guidance that we have in the second quarter, yes, it does.

David Heikkinen – Tudor, Pickering & Co.

Okay. Thanks.

Operator

(Operator Instructions). We’ll take our next question with Jeff Hayden with Pritchard Capital. Please go ahead.

Jeff Hayden – Pritchard Capital Partners

Thanks. Morning, guys. Most of my Fayetteville questions have been hit already, so I guess jumping to the Marcellus. You guys have been adding more acreage. I’m just wondering if you could give us any colour on what you’re having to pay out there as far as lease instalments, what kind of royalty you have to give. And what are your plans for drilling horizontal wells?

Harold M. Korell

Well, we won’t give you guidance on what we’re paying in royalties. We’re just at the early stages of drilling vertical wells now and sampling the rock and doing that kind of physical work and all the assessment that we would want to do. Not a lot of help to you or not a lot more new information there because we’re just in the throes of doing those vertical wells.

Jeff Hayden – Pritchard Capital Partners

Okay. Thanks, guys.

Operator

(Operator Instructions). We’ll take a follow up with Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Thanks. Just jumping to East Texas really quickly. I think you all said you had 95,000 acres in the Angelina trend. Could you tell me, is that all perspective for James Lime? And if you could also draw some conclusions based on what you know now what you think spacing is, well cost is, and potential recoveries of some of those wells you all are drilling out there.

Harold M. Korell

Well, Scott, I would say the acreage is all potential, which is real encouraging. We certainly haven’t sampled it densely. We have drilled wells across a pretty far area from east to west. So it is definitely all perspective and we’re trying to understand what drives some of the rates we’re seeing. We’re seeing variable rates there.

The spacing is up in the air. Maybe to guide you a little bit, I would say we’re drilling longer laterals there. We’re drilling most wells somewhere in the 5,000 foot lateral length. So we’re starting with a little bigger footprint there. Maybe something kind of nominally around a 160-acre kind of thing. We’ll have to see as we go how the wells perform and what that ultimate drainage is, but we’re real encouraged so far.

Scott Hanold – RBC Capital Markets

What are some of the AFEs (sic) on the wells you’ve drilled to date?

Harold M. Korell

They’re high breezed to $4 million.

Scott Hanold – RBC Capital Markets

Thanks.

Operator

And we’ll take our next question with Mike Scialla with Thomas Weisel Partners. Please go ahead.

Mike Scialla – Thomas Weisel Partners

Hi, guys. I’m wondering with the improved costs you’re seeing in the Fayetteville. Are you seeing any improvements in the number of wells? You’ve had some mechanical difficulties with some wells. Are you seeing improvements there in terms of the percentage of wells that you’re running into problems?

Harold M. Korell

Yup. Definitely, Mike. I think some of the good drilling practices that we’ve established are helping there. I think the 3D seismic is helping there. I can’t give you an absolute number, but I do know weekly when we look through all the activity that the number of problem wells and wells needing to be sidetracked is dropping off and that’s helping for sure.

Mike Scialla – Thomas Weisel Partners

Great. And any update on the severance tax situation in Arkansas?

Harold M. Korell

Yeah. It is law. It is resolved and it’s been signed by the governor and rather than me repeat the terms of it, probably just, Mike, you can go out and get that. I think it’s a reasonably good outcome for us and for the industry and it will still keep the activity moving along. All that begins I think in January of 2009. But we were able to get a reasonable rate with exemptions. Basically the rate on the first three years for wells drilled in the Fayetteville will be 1.5% and then if you got a bad well that hasn’t paid out after that period you can apply for an extension of a year. And then there’s a 5% severance tax rate after that time and it’s on a per well basis. Then late in the life of the wells, when the production rates drop down below, I think, 100 MCF a day, then the rate goes to 1.25% or something like that. So I think a reasonable outcome to all of that.

Mike Scialla – Thomas Weisel Partners

Great. One quick one on the Marcellus. Can you comment at all about any industry activity? Anything going on around your acreage by other operators?

Harold M. Korell

Yeah. We’re seeing a lot more permits, Mike. There’s some public data talking about rates starting to emerge from horizontal wells that are pretty encouraging and pretty close to us. We’re seeing some horizontal wells being drilled. The answers are coming quicker now. With the state in Pennsylvania the way the rules work, there’s not a lot of reporting there that has to happen, so that’s a challenge. But definitely the activity has picked up. There are some publicly reported rates that are encouraging on horizontal wells and permits in and around where we’re active.

Mike Scialla – Thomas Weisel Partners

Okay. Thank you.

Operator

And we’ll take a follow-up question with David Heikkinen. Please go ahead.

David Heikkinen – Tudor, Pickering & Co.

Richard, just thinking about the areas where you have 3D seismic coverage, how much of the acreage would you exclude for faults or cuts where you wouldn’t want to drill?

Richard F. Lane

Well, we don’t have the carsting (sp) terminology kind of, I think that you’re referring to, is grown out of some of the challenges in the Fort Worth Basin where they have carsted (sp) carbonates underlying their objective that are water bearing. We don’t have that anywhere that we have drilled and don’t expect to have that. So it’s a much more minor problem and really unit specific. If we have faults it doesn’t mean that we can’t drill the well; we may be placing it in a little different spot.

I know I’m not helping you with some kind of a percentage there, Dave.

David Heikkinen – Tudor, Pickering & Co.

I’m just trying to think through risk factors in the play where you’ve been and what it sounds like. Surface access from pads, directional access. You’ve been playing around with a lot of things.

Richard F. Lane

Right. You know, I would say this: There will be wells that we don’t want to drill in the play because of geologic reasons, but really when you look at it right now it’s providing us a tool to drill the best ones first. So we’re pushing those out.

David Heikkinen – Tudor, Pickering & Co.

Thanks, guys. I appreciate it.

Operator

We’ll take a follow up with Joe Allman with J. P. Morgan. Please go ahead, Sir.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Thanks again. Harold, can you talk about people with constraint. Not having enough people with the constraint previously. Could you characterize where that constraint is for you folks now?

Harold M. Korell

Well, I would say this: If you just took and said, what’s the overall package of wells we have as a company, and say, how do you create the most net asset value, we’ve got thousands of wells to drill in the Fayetteville Shale. So something’s holding us up. For the most part I would say that it would be people to accelerate the drilling activity. We’re continuing to hire new people. We’re continuing to recruit people. Our organization is more settled, I would say, than it was a year ago for sure when we had reorganized and shuffled everybody around. I think that even with the same number of people we’re able to accomplish more drilling and completion and more analysis of what we’re operating, and what we’re operating is telling us.

So we’re moving up that curve and there will be some point in time where I would say we would be prepared to go faster. And by faster I mean drill more wells and put more rigs out there. If we’re able to drill we’re getting some benefit now. It’s taking less days to drill an individual well, which automatically should move us in the direction of drilling more wells.

But then there will probably be some point where we want to put more drilling rigs out here and we just have to keep that all balanced, the people and the capital and the take-away capacity and all of those things that go into it. Services. But I would still say as far as keeping our helicopter going up and to the right people is a constraint. It’s not one that’s a constraint just for us. It is entirely across the industry. We’re all hammering away at each other. There comes a point where it’s hard to – I’d like to see some more M&A happen. That’s always when there are people available and somebody disappears. Unfortunately, where prices are, it’s less likely to see in my view combinations other than special cases.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

And lastly, can you talk about any prospectivity on your acreage for the (inaudible) shale?

Harold M. Korell

I can’t really talk about it.

Richard F. Lane

It’s present in those counties where we’re active, Joe. We’re just starting to look at that, but can’t give you a lot of colour on it just yet. The interval is definitely present there.

Joe Allman, CFA – J. P. Morgan Securities, Inc.

Okay. Very helpful. Thank you.

Operator

And at this time we have no further questions. I’d like to turn it back over to management for any additional or closing remarks.

Harold M. Korell

Okay. Well, thanks, all of you, for joining us today. We’re excited and proud of the results that we’ve had in this quarter, quite frankly. I think it shows that the focus we have on present value creation and getting the most that we can per dollar we invest is working and that our teams of people – and some of them would be listening on the phone today – feels good for those of us here sitting at the table, but I want our employees to know and our people to know that clearly the efforts that they’ve been making over the past couple of years are starting to show here in the results and as we’re making improvements. Particularly in the Fayetteville. Some of the other things we’re doing as well in the East Texas and in our conventional Arkoma Basin which are less romantic but nonetheless adding volumes and reserves to our base level of performance.

So thank all of you for being there. We look forward to the rest of the year. We’ll have some exciting things, I’m sure, to share as we move on through 2008.

Operator

Once again, ladies and gentlemen, this will conclude today’s conference. We thank you for your participation. You may now disconnect.

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Source: Southwestern Energy Company Q1 2008 Earnings Call Transcript
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