西南能源 (SWN) 2009 Q4 法說會逐字稿

Greetings. Welcome to the Southwestern Energy Company fourth quarter conference call. At this time, all participants are in a listen only mode. A brief question and answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions. Afterward, you may feel free to re-queue for additional questions. (Operator Instructions). As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Harold Korell, Executive Chairman of the Board for Southwestern Energy Company.

Good morning and thank you for joining us. With me today are Steve Mueller, our Chief Executive Officer; and Greg Kerley, our Chief Financial Officer. If you've not received a copy of yesterday's press release regarding our fourth quarter and full year results, you can call 281-618-4847 to have a copy faxed to you. Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the Risk Factors and Forward-looking Statements section of our annual and quarterly filings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Well, 2009 was an exceptional year for Southwestern Energy. We saw several milestones this year, including setting new records for production, reserves, reserve replacement, and cash flow, all in a year where we saw natural gas prices that were at a seven year low. We celebrated our fifth anniversary of the Fayetteville Shale play while also reaching a production milestone of 1 Bcf per day from the play. We drilled and completed our 1,000th well in the play, on our way to completing many more in the years to come. Finally, we continued to have an industry leading low cost structure, as our finding and development cost of $0.86 per Mcf and lease operating expense of $0.77 per Mcf in 2009 are among the lowest in the industry. This is all pretty amazing, when considering that just five years ago we set all this in motion with the discovery of the Fayetteville Shale.

Meantime, in our other areas things are continuing to go well in our East Texas James line and Haynesville activities, and in Pennsylvania where we have just started an active drilling program. I will now turn the teleconference over to Steve for more details on our E&P and midstream activities and then to Greg for an update on our financial results, and then we will be available for questions.

Good morning. As Harold stated, we had an outstanding year in 2009 and our operational metrics are some of the best in the industry. Our production grew by 54% to a record 300 Bcfe equivalent, primarily as a result of the growth from our Fayetteville Shale, where our production grew 81% to 243 Bcf. We also produced 35 Bcfe from East Texas and 22 Bcf from the Arkoma Basin. Our year-end proved reserves increased by 67% to a record 3.7 TCF equivalent.

Approximately 100% of our reserves were natural gas and 54% were classified as proved developed, down 8% from 62% in 2008. We are also one of the few companies that have recorded net positive reserve revisions as the improving performance from our Fayetteville Shale wells more than offset negative price revisions due to low gas prices and some performance revisions in our East Texas and Arkoma Basin programs. For the last three years, our reserve replacement has averaged over 500% of our annual production. We replaced 592% of all 2009 production at a finding and development cost of $0.86 per Mcf equivalent, including revisions. Excluding revisions, we replaced 561% of our production at an F&D of $0.91 per Mcf.

Now, let's talk a bit about our operating areas. The Fayetteville Shale continues to deliver exceptional results. We invested approximately $1.3 billion in our Fayetteville Shale drilling program during 2009, adding 1.8 TCF of new reserves at an F&D cost of $0.69 per Mcf. This includes net upward reserve revisions of approximately 238 Bcf as our improved well performance more than offset negative revisions due to the lower gas prices. The finding and development costs excluding these revisions was $0.80 per Mcf.

Total proved net gas reserves booked at the Fayetteville Shale play at year-end 2009 were 3.1 TCF, more than double the reserves booked at the end of 2008. The average gross proved reserves for the undeveloped wells included in our year-end 2009 reserves was approximately 2.2 Bcf per well, up from the 1.9 Bcf per well at the end of year 2008. And based upon our current drilling pace, we have approximately two years of drilling inventory booked as PUDs.

During 2009 we continued to improve our drilling and completion practices in the Fayetteville Shale, where horizontal wells had an average completed well cost of $2.9 million per well compared to an average of $3 million per well in 2008, as a decrease in our drilling times and other savings more than offset a 13% increase in lateral length. Our average initial producing rates improved 25% over last year as wells placed on production during 2009 averaged the initial production rates of approximately 3.5 million cubic feet per day compared to the average initial production rate of 2.8 million cubic feet per day in 2008.

Mid-year 2009, we celebrated reaching 1 Bcf per day from the Fayetteville as gross production from our operated wells climbed from approximately 720 million cubic foot per day at the beginning of 2009 to approximately 1.2 Bcf a day at year-end. Recently we have had some delays due to operational issues and the colder weather that have caused 25 fewer wells to be put on production during the last few months than originally planned. As a result, we have added two additional drilling rigs to help us catch up on our projected well count, which we expect will happen sometime in the third quarter. We are currently running 22 drilling rigs in the Fayetteville shale play, 16 that are capable of drilling horizontals and six smaller rigs that are used to drill the vertical sections of the wells.

In our East Texas operating areas, we had excellent results posting production growth of 10% to 34.9 Bcfe with reserves approximately 330 Bcfe at year-end. In 2009, we invested approximately $167 million and participated in 46 wells in East Texas, of which 33 were successful and 13 were in progress at the end of the year, resulting in a 100% success rate. We continue to have good success in our James lime carbonate play and through December 31, 2009 and participated in a total of 77 horizontal wells. Of those, 43 were operated by us and placed on production on an average growth initial rate of 9.8 million cubic feet per day. We also kicked off our drilling program targeting the Haynesville and Middle Bossier shales in Shelby and St. Augustine Counties in 2009 with very good results. After our first horizontal well production tested at 7.2 million cubic foot per day in the first quarter 2009, we drilled four additional wells in the Haynesville shale, which production tested 13.4 million, 16.7 million, and 21 million a day, and 18.1 million per day respectively.

Additionally, we completed our first well in the Middle Bossier formation, which production tested at 11.3 million cubic foot per day. We are currently completing our sixth Haynesville well, the Red River 620 1-H and drilling at two additional Haynesville wells in the area, the Red River 619 #2 1-H and the Owens #1, both of which will be completed sometime in the Second Quarter. In total, we have approximately 42,300 net acres we believe are prospective for the Haynesville and Middle Bossier shales and our average gross working interest is approximately 61%. In addition to the James lime, Haynesville, and Middle Bossier targets, we placed our first Pettet oil well in production. The Acheron 2H was placed on production in January at initial production rates of 465 barrels of oil per day plus 2.5 million cubic foot of gas. We are currently participating in two Pettet wells, which are being completed.

In our conventional Arkoma program, we had approximately 208 Bcf of reserves at year-end 2009 and produced 22 Bcf, compared to 24.4 Bcf in 2008. Our production decreased during 2009 primarily due to the significantly lower capital investments in the area as compared to 2008. In 2009, we invested approximately $40 million in our conventional Arkoma drilling program, participated in 20 wells, of which 15 were successful and three were in progress at year-end, resulting in an 88% success rate.

At December 31, 2009, we had approximately 149,000 net acres in Pennsylvania prospective for the Marcellus Shale. Our undeveloped acreage position as of December 31, 2009 had an average remaining lease term of five years, an average royalty interest of 13%, and was obtained at an average cost of $594 per acre. During 2009, we invested $40 million in Pennsylvania, almost all of which was for acquisition of acreage, including approximately 22,800 net acres in Lycoming County that was purchased for $8.7 million or $382 per acre. We are currently drilling our first horizontal well since 2008 in Pennsylvania. The Heckman Camp #1 well is located in Bradford County and first gas production is expected in the area in the second quarter of 2010.

In summary, we're very pleased with the results in 2009 and our planned capital investment plans for 2010 continue to build on that success. While we are very proud of our accomplishments in 2009 and over the past five years, we also know that we have much work to do. We know that our disciplined approach to capital investments, focus on organic growth, and financial flexibility will keep us extremely well positioned during both the good and the challenging times. We're looking forward to what lies ahead in 2010 and the many years to come.

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

Thank you, Steve, and good morning. As Harold and Steve said, we had an exceptional year in 2009 both operationally and financially, despite natural gas prices falling to their lowest levels in seven years.

For the calendar year, we reported net income of $523 million or $1.52 per share, excluding a $558 million after-tax ceiling test impairment of our oil and gas properties during the first quarter of 2009. Cash flow from operations before changes in operating assets and liabilities was up 23% to $1.4 billion as our production growth more than offset the effects of significantly lower natural gas prices. For the fourth quarter, we reported earnings of $158 million or $0.45 a share, a 51% increase over the prior year period, as the significant growth in our production volumes more than offset the decline in our average realized gas price. Our production totaled 89 Bcf in the fourth quarter, up 55% from the prior year period, and we realized an average gas price of $5.29 per Mcf, down from $5.93 in 2008. Our commodity hedge position increased our average realized gas price by approximately $1.50 per Mcf in the fourth quarter. We currently have 66 Bcf or approximately 16% of our 2010 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.02 per Mcf. Our detailed hedge position is included in our Form 10-K that we filed yesterday.

Operating income of our E&P segment, excluding the non-cash ceiling test impairment, was $750 million in 2009 compared to $814 million in 2008. For the year, we grew our production to 300 Bcf equivalent and realized an average gas price of $5.30, which was down approximately 30% from the prior year. We continue to have one of the lowest cost structures in our industry, with a full cycle cash cost of approximately $2.14 per Mcf in 2009 and a three year average of $2.75 per Mcf. This includes our F&D costs, lease operating costs, taxes, G&A and interest expense. As Steve noted, our finding and development cost was $0.86 per Mcf in 2009, including revisions, down from $1.53 in 2008. Our lease operating expenses for unit of production were $0.77 per Mcf in 2009, down from $0.89 in 2008. This decrease was primarily due to the impact that lower natural gas prices had on the cost of compressor fuel during 2009.

Our general and administrative expenses per unit of production declined to $0.35 an Mcf in 2009, down from $0.41 in 2008. This decrease was primarily due to the effects of our increased production volumes, which more than offset the effects of increased payroll, incentive compensation, and other related employee costs primarily associated with the expansion of our operations in the Fayetteville Shale. We added a total of 335 new employees during 2009. Taxes other than income taxes were $0.11 an Mcf in 2009, down from $0.13 in the prior year due to the lower commodity prices and the change in the mix of our production volumes. Our full cost pool amortization rate also declined, dropping to $1.51 per Mcf in 2009 from approximately $2 in the prior year. The decline was due to a combination of the ceiling test impairment recorded in the first quarter of 2009, our lower finding and development costs, and the sale of natural gas and oil properties in 2008.

Operating income for our Midstream Services segment doubled in 2009 to $123 million. The increase was primarily due to increased gathering revenues related to production growth in the Fayetteville Shale partially offset by increased operating costs and expenses. At December 31, 2009, our midstream segment was gathering approximately 1.3 billion cubic feet of gas per day through 1,137 miles of gathering lines in the Fayetteville Shale play compared to gathering 802 million cubic feet of gas per day a year ago. We invested $1.8 billion during 2009, approximately equal to our investments in 2008, and we expect that our total capital investments for 2010 to be approximately $2.1 billion.

There's clearly uncertainty today regarding natural gas prices, so our capital plans will remain flexible. If we see a repeat of the low gas prices we saw in 2009, we'll actively manage our capital program and make reductions in our 2010 plans. However, if gas prices rebound during the year, we could increase our plan investments and accelerate the development of the Fayetteville Shale by adding additional drilling rigs. We have a strong balance sheet with significant liquidity and financial flexibility. At year-end, we had $325 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.1% and total debt outstanding of a little less than $1 billion for the Company. That left us with a debt to book capital ratio of 30% at year-end and a debt to market cap ratio of only 6%.

That concludes my comments. And I'll now turn it back to the Operator, who will explain the procedure for asking questions.

(Operator Instructions). Our first question is from the line of Scott [Wilmuth] with Simmons & Company.

Hi guys, following up on the flexibility of the CapEx budget. Could you put some magnitude around it? Say we're in a $4 gas price for 2010, what type of magnitude decrease in the CapEx budget would we have and ultimately what would that do to guidance?

Well, if you look at the guidance that we already prepared and sent out publicly in December, there's about a $300 million swing in our cash flow if we were to average $4 versus $5. So you would see us when we [release] our capital program to try to stay fairly in the same range that we expected for our total net borrowings for the year.

And let me add to that. The two places you'd see that is probably some of the new venture things, because if gas prices are low you don't need the new ventures as much. And then also in some of the stuff we're doing in East Texas, where most of that is HBP, so it's really -- as we've got the dollars, we can invest there.

So impact to guidance would be minimal?

We haven't done the calculations, but that's probably right.

Okay, and then just one other question. You mentioned in the release operational and weather related issues. Were all those operational issues due to the weather or can you just give me a little more color on that?

It was all due to the weather, and when we say operational and weather, we had several snowstorms. And if you look at that chart included with the press release on the production you'll see some little bumps and glitches in January. We had some little bumps in February as well, but what happens is you get a bunch of snow and ice out there and you can't move the equipment, and if you can't move the equipment, you can't drill as fast. And that's the combination.

Okay, thanks guys.

Thank you. Our next question is from the line of Jeff Hayden of Rodman and Renshaw.

Good morning guys. A couple questions. Starting with the Haynesville, could you guys give any color on what you had in terms of reserve bookings from the Haynesville at year-end, number of locations as well as EURs you had on them?

Well, I can start by talking about the EUR. I believe the EUR is just over 5 Bcf on our wells. We're looking at the numbers right now, trying to figure out exactly what we had from a well count book. There wasn't that many wells total that we had booked in the year. And again, if you think about our acreage position out there, we have a metal block we call [Jumble] Acreage, if at any of our presentation material, we have now drilled all four corners of that block. So we're feeling comfortable about the acreage, but we certainly don't have that completely booked. What we had booked at the end of the year was a total of 30 Bcf to the Haynesville, and that included seven proved locations and 10 PUDs for a total of 17 total locations.

Okay, appreciate that, and then jumping up to the Marcellus really quickly, just wondering if you can give us an update on how you're looking at the drilling program for 2010 in terms of where you are going to spot the wells, whether it's Bradford, Susquehanna, Lycoming, et cetera? And then building on that, an update on the takeaway capacity that you're looking at and how you're going to manage that?

Well, the rig that we're running, we'll drill between 20 and 24 wells this year. It is going to be all in Bradford County. It's right on top of -- within a mile or two of the Stage Coach Pipeline, and we have firm on that pipeline today of 20 million cubic foot and we're building that going forward. And that's the reason we're drilling where we're at, because we do have the capacity on that line to be able to do that. We'll participate probably in another 20 wells. Most of those will be -- a little bit maybe in Bradford, but most will be in Susquehanna, and we'll have a minority interest in those wells. And whatever the operator there is, we'll have the takeaway, so we don't have to worry about that portion. Over the next year, we'll keep one rig running and then you'll see us build that activity into the future. We'll say the one area that will have the less drilling over the next couple of years will be Lycoming County, but that's more 2012 and beyond where you see much drilling there.

All right, I appreciate it guys.

Thank you. Our next question is from the line of Scott Hanold with RBC Capital Markets.

Thanks, good morning.

Good morning.

When you look at the Fayetteville, were any of the prior PUDs in the Fayetteville let go from last year to this year because of low gas prices?

There were some that -- there's a very small amount that did. I don't know.

And is it fair to say then that at the -- I think was it $3.87 price or that you had to use for the reserves, most of those Fayetteville PUDs held up [economic yet]?

Yes.

Okay, and you'd mentioned you have two years of PUDs currently booked at this point in time. I know it's not perfect math, but when you look at how many offsets per PDP, what does that look like?

We'll have to calculate that one for you, Scott. It's something around 0.8 for PDP.

Okay.

Total number of wells was 1,150 that we have booked as PUDs right now.

And that 2.2 Bcf EUR on your wells, that seems pretty conservative relative to the performance you've been seeing. Has there been a difference in these newer wells you're putting online where you book them at a much higher rate? I know there's a range, but on average is it a pretty clear trend that your 2009 adds were significantly higher than prior years?

Let me explain how we do the reserves and I'll let you figure out where you want to go with the question from there. What we do, we break the entire Fayetteville Shale into several different areas. We look at the production from the wells in those individual areas and then we look at what we're going to drill in the future. And the wells that we drill in the future in those particular areas get the average from whatever you've done in the past, and that average that you've done in the past has to have enough production on it to count. And so if you think about any of these areas and break it up, we've got roughly 30 different areas we break it up into. You're only using wells that are eight months or older for the most part in that average, so any of the things that it's going on today isn't even affected in our overall reserve numbers.

Okay, now I got it. That makes it clear. And one last question if I could. PV10 value, I'm sorry if I missed that, what was your year-end PV10 value, and if you have that between the PDPs and the PUDs that would be great.

I don't have that sitting right here, Scott. We'll look it up and answer that one in a while.

I appreciate it, thanks.

Our next question is from the line of Michael Scialla with Thomas Weisel Partners. Please go ahead with your question.

Good morning guys. One of mine, sounds like you're probably going to have to look up as well if you have it, kind of along the same lines as Scott's question. I was wondering if you ran a sensitivity at a higher price than the $3.87 on your proved reserves for a PV10.

I can tell you we haven't.

Okay. The second one, you mentioned the Pettet, wondering how big that could be and are any of the new ventures targeting more oily plays or are you sticking with the gas plays at this point?

As far as the Pettet goes, we're trying to figure out how big it could be. Right now, there's about six wells that Cabot has drilled. We have done our first well and are participating in these other two I talked about, and it looks like if you got $60 oil, it's going to be a pretty good play, and with that $60 type oil range and we need probably four or five more wells to see, there may be 100 type wells, 100 wells that you have to drill out there. But it's way early.

It could be we drill four or five more wells and it's six more wells you have to drill. So we just got to figure that out from that standpoint. And then as far as targeting new ventures, we're targeting oil or gas, if you think about any of these plays that are new, we just talked about the fact that we're -- it's been five years since we found the Fayetteville -- from the time you come up with the idea to the time you really get significant production is going to be three to five year period. And I really can't guess what's going to be a better product, gas or oil down the road. So what we're doing is looking for the best 1.3 PVI projects, and if they happen to be oil they are oil, and if they happen to be gas they will be gas.

Thanks, Steve.

Thank you. Our next question is from the line of Brian Singer with Goldman Sachs.

Thank you, good morning. Going back to your comments on capital allocation, given the lower gas prices here, can you talk more about the decision to add the two rigs to make yourself whole on Fayetteville drilling and then talk a little bit more about the midstream commitments and how that allows or does not allow for flexibility in Fayetteville activity?

Let me start with the midstream first. Our guidance for the year in midstream was actually a little bit higher capital program than we had last year in midstream, and we'll be drilling a large number of wells in the Eastern -- towards Eastern central area to hold acreage and we'll we building out our midstream there. Our midstream per well or per pad is going to be about 20% longer this year than it was last year because it builds up that program and that will give us flexibility into the future. And we still got probably at least two more years of that $250 million to $280 million a year capital to really build out most of the program we have. So it is just continuing to do that. It's a little bit higher this year than last year.

As far as adding the rigs, just like we did in 2009, we're trying with about 30% of our wells just to hold acreage. The other wells are still trying to learn things. And as we downspace and do closer spacing, we're learning that certain areas look like they are going to be a little tighter spacing and other areas will be wider spacing, and we need to get that learning done very quickly so we can actually get on to the pad drilling portion of it. So the 25 wells isn't so much a production type number that we're trying to do something with. It's that learning part of it. We had the opportunity to add two rigs early this year on a relatively short-term contract. Both of those rigs will expire before the end of the year, and we thought it was a good bet going back again -- if the gas price is $4, you'll see us drop those rigs later in the year. If it's $6, we've got them working and in shape that we can accelerate going into next year. So it gave us a good bet and it helped us learn at the speed we want to learn at.

Thank you, that's really helpful. And then secondly, on the Haynesville, Bossier, and Marcellus, do you think about those assets as keepers or would you consider a joint venture to either accelerate activity or improve the balance sheet, et cetera?

If you think about joint ventures in general, it's just another way to provide some kind of capital. And at this point, as we said, we can manage what we need to do with just moving rigs around or moving rigs up or down. So I don't think we're right now thinking about joint ventures anywhere, whether it's Haynesville or anything else. We have stated in the past that -- and we stated here again today that if you rank our quality of our projects, both I think what we have in Pennsylvania and Fayetteville, worked with $4 numbers on the gas. And when you get into East Texas you're going to need to have a $5 on most of what's going on, and that's why we said if it was $4 gas we would adjust East Texas down.

And Steve, I think I would add to that. We do have a joint venture in the Haynesville and Bossier, we have a partner in that. And I don't think it would be a smart thing to do to have another partner in that. And as a practical matter, because of the way the acreage is distributed in the Marcellus, we also have quite a few partners in the Marcellus acreage that we have. So as Steve said, we have the ability to fund and hold this acreage and we don't find ourselves in a financial squeeze. So we aren't compelled to do any of those kind of things right now.

Thank you very much.

Our next question is from the line of Bob Christensen with Buckingham Research Group. Please go ahead with your question.

Yes, thank you. How thick a section of rock are we working with in your latest Bossier and then some of your latest Haynesville?

The average thickness for the Haynesville is just over 100 feet, and if the Bossier works, its average thickness is very similar to that.

Okay, that's all I have, thank you.

(Operator Instructions). Our next question is from the line of Rehan Rashid with FBR Capital Markets.

Good morning. Just a capital intensity related question. So the latest numbers I guess are $3 million for a 4,300 feet lateral. Does this include the impact of your own sand production?

Everything we told you is historical data. As we've talked about and we gave guidance on, the sand plant is up and operational. That sand plant will save us between $130,000 and $150,000 per well that it's used on. And so we expect that with the same lateral length in 2010, our overall cost will be down. And I think we did a press release at the end of the year and talked about $2.75 million average.

Got it. So to take it beyond that $2.75 million, outside of let's just say pad drilling synergies, is there anything else from a technological standpoint that could accelerate the spud to release or any other cost reduction?

Well, we're working on all kinds of things and two of the rigs that we're running right now, RAC rigs that have some of the characteristics, and one of them has I think mostly characteristics we want to use on pad drilling. And we're learning what those might be able to do for us, so we're continuing to work on the drilling side of it. Completion side, we're averaging between 12 and 14 frac stages, but I can tell you we're playing with a mix of the water versus sand and maybe even the mesh of the sand. And depending on how that mix changes and if those stages would change, there's some cost savings in there. And as you mentioned, we're not to pad drilling yet.

In 2010, we'll actually drill fewer wells per pad than we did in 2009 and you won't see us really start ramping up until 2011 where we're doing pad drilling. There will be a lot of synergies on the pad drilling that will put downward pressure on that cost. So there's certainly things we're working on, but I don't think any one of them is as much as the $130,000 to $150,000 we have in the sand.

Got it. Got it. A couple of miscellaneous questions. So going back to the 2.2 B's per well, what -- any kind of thoughts on the average lateral length associated with that? I know you said eight months lag.

Well, the average lateral length of the PUDs in our reserve report is 3,700 feet.

Okay, good, and the negative reserve revisions, what vintage wells would these be, just trying to think through?

We have very few wells that were five years or above that we had to do anything with that direction. We had -- most of the negative revisions were price related, and the ones that were performance related for the most part were in the Overton Field, and those just weren't performing the way we had them booked frankly.

Okay.

And that is not a really big number, but that's where most of those revisions were at.

Got it, got it. From a downspacing standpoint, I know 20 pilots going on -- is it too early to quantify what percent of the area gets as close to 30-acre spacing and some higher?

Yes, and let me just tell you, we talked before about the fact and I think we released some information that we were doing somewhere around 12 to 13 at very tight spacing. We now increased that this year. We'll end up well over 20 at tighter spacing, and the reason for that is we're getting mixed results. We've had about half of the tighter spacing work very well and give us our 1.3 PVI, and we've got half that we've got question marks on. So we'll have to expand that program and that goes back to Brian's questions earlier about wanting to catch up on those 25 wells. We're just getting the mixed results that tells you that you must be getting close, but we got to just get some more information so we can learn more about it.

Okay. I think that is it. Thank you.

Let me jump in here, Scott Hanold asked a question on what our PV10 was on our reserve report for the Fayetteville Shale for both of the PDP and PUD. The PDP -- and this is at the $3.87 NYMEX average that we had, and then there's going to be a basis differential lower than that, but the PDP was $2.2 billion, the PUDs were $23 million. So you can see the PUDs are just around the PV10 mark at the $3.87 minus roughly $0.30 basis differential.

Our next question is from the line of Jud Sturdivant with OCAP Management.

Hi guys, congratulations on another record-setting year.

Thank you.

Listening to several earnings calls, I've noticed a trend in pricing pressure from the service industry, primarily within pressure pumping and a little pushback on the rig prices. Can you comment on how this will affect your F&D costs going forward or any color you might have on the issue? And secondly, can you comment on your basis differential of $0.39 versus $1.80 in 2008 and 2010 expectations? Thanks.

Well, I will talk a little bit about the costs and I'll let Greg talk about the differential. But as far as the costs go, one of the reasons we own our own rigs. And I'll remind everyone we own 11 of the bigger rigs running the Fayetteville Shale -- one of the reasons we own our own sand mine is that was the only way you could only hedge those costs over a long period of time. In both of those we'll use the Fayetteville Shale -- we don't have to use anywhere else. So that allows us to have a relatively constant cost from those angles. We are lengthening out the steel and what we buy -- normally we buy a quarter ahead, we're trying to lengthen that out significantly right now to control those kinds of costs.

And then on the pumping service side, it really depends on what part of the country you're in, how much pressure you're getting on the pumping service. Certainly you're seeing costs go up in the Haynesville and in the Marcellus -- just because the equipment is not there yet, you're seeing some upward pressure. The other side of that equation for us is we're continuing to learn and take costs out and if you think about what we've done over the last three years, in 2007, it cost us $3 million to do a 2,700-foot lateral. Today it's $2.9 million to $3 million to drill a 4,300-foot lateral, and we're working hard with whatever we do on the learning side that we can offset any of those kinds of costs without going forward.

Is it a fair assumption to expect $100,000 per frac stage going forward?

We're a little bit less than that on our average frac stages.

Okay, thanks.

Just to follow-up on the basis question, we've seen basis continue to tighten. Our current guidance is we expect somewhere around between $0.10 to $0.20 of negative adjustment to get to our price, so that's down considerably from more than a year ago for sure.

And let me jump in. We do have 140 Bcf hedged at that low number. So we know at least over the near term, we'll have that basis. And when you look at the basis across the United States, it has collapsed significantly -- if you look back at 2008, there are wide swings in various basins. Today, almost seeing where you're at, you can almost get the best price you saw in your local market as opposed to trying to get to the East Coast.

Thank you.

Our next question is from the line of David Heikkinen with Tudor, Pickering, Holt.

Good morning. Just had a question on your 2009 proved reserve category summary of net acreage and net undeveloped acreage, to make sure I'm understanding it. The undeveloped acreage -- is that just acreage that has no wells drilled on it, is that a fair -- ?

It has no producing wells on it.

And then the delta between those, that's not that that acreage is fully developed -- basically we should just think about you booked 1,150 PUDs to the Fayetteville, and that all of the rest of the locations that we may come up with using spacing assumptions would be the difference between producing plus PUDs and then remaining inventory, is that fair?

That is correct, and I'll use the Fayetteville Shale as an example. In the Fayetteville Shale, if you drill one well and it's 640-acre spacing and put it on production, that holds the whole 640, that would make it developed acreage. Then, you come back later and our 600-foot spacing we're talking about would be at least 10 wells total so we would have to drill nine other wells on that section, even though as an acreage it's counted as developed acreage.

Okay, just making sure. That's helpful. And then you answered the question of the split of PDP for each of the areas. Just curious in trying to get sensitivity around the PUDs for East Texas or the Arkoma. Do they go down to that same relatively low value, the same ratio? Or is it less sensitive because there's future development?

Well, the PUDs for the most part -- the PUDs in East Texas and Arkoma need a little bit higher gas price, but you put it in perspective, 99% of our PV value as a Company comes from the proved developed, so there's almost nothing in the proved undeveloped. It's all 10% and 8% type discount numbers.

Okay, everything else has been answered, thanks.

Thank you. Our next question is from the line Joseph Allman, with JPMorgan.

Good morning, everybody. I think you answered this in a way, but when you talked about the PUDs being economic at $3.87, you booked your reserves based on PV0 as opposed to PV10, and at $3.87 most of your Fayetteville Shale probably isn't economic on a full cycle basis, is that correct?

The 2.2 Bcf well is just about economic. It's $3.90, $3.87, $3.90, so economic gives you PV10. To get our 1.3 PVI, we need it in the $4.30 range for that 2.2 Bcf average. Now again, that's the average of what we have out there. We've got some PUDs that are significantly higher than that and we've got some that are lower than that. Those lower ones obviously were booked at PV0 or greater.

Got you, and then when you gave the PV10 of $2.2 billion, I think, Steve, you said that was just the Fayetteville?

That was just the Fayetteville.

Okay, do you have the numbers for the whole Company?

Oh, I'm sorry, that was total. I'm sorry. The Fayetteville -- and to go back to this, the number I gave you before, the $2.2 billion is the total Company, the Fayetteville was $1.9 billion for the PDP -- and $1.9 billion for the PDP, or proved I'm sorry.

And what about for the PUDs?

$39 million for the PUDs.

Okay, got it. So that suggests that--

So the difference between the $39 million and $23 million, whatever that is, $16 million of less than PV10.

Got it. Thank you very much.

Our next question is from the line of Nicholas Pope with Dahlman Rose.

Good morning, guys.

Good morning.

Just back to the spacing you said it was successful in [65] acres, like are you seeing much interference, whenever you look at the 700-foot spaced wells or what's it look like at this point?

We're drilling everything today at least 600 feet or closer, and we're seeing about 15% -- between 12% and 15% interference with that spacing.

And then, Mike, I guess for the rest of the year you talked a lot about like that 300 to 500 foot tests that are going to be known. Have you all done many of those wells yet?

We've got information on eight. And now some of that information doesn't have a lot of production on it, but we've got information on eight and I can tell you that on those eight, there's four that give very good economics, well above our 1.3 PVI. There's a couple that are bouncing around and may make a 1.3 PVI, and there's a couple that aren't good at all.

Okay, great. That's helpful. And then just -- I was wondering with the press release you all put out in the filing you had on that rights agreement, the acceleration of the exploration on that rights agreement, is there anything to be read into the removal of that rights agreement?

There really isn't anything to be read into it anymore than companies are getting beat up for corporate governance type things and this is one of those corporate governance issues. You'll see that we've done a couple of different things as a Company. One of them is we just decided it wasn't worth the effort to keep the rights agreement out there. We also put in our policy for what our executives and Board should have for total stock to put that more in typical corporate governance. So we just reviewed our corporate governance things and we tweaked it and one of those tweaks was we decided we didn't need the rights plan.

All right, looks very helpful, that's all I had.

Our next question is from the line of Brian Kuzma with Weiss Strategies Please go ahead with your question.

My questions have been answered. Thanks for the corporate governance changes.

Our next question is from the line of Dan McSpirit with BMO Capital Markets. Please go ahead with your question.

Gentlemen, good morning and thank you for taking my question. Certain operators in the Haynesville at least on the North Louisiana side have experimented with and even reduced the choke size at which they flow the wells. Can you comment on the benefits of that from your view of the world and whether or not you'll need to do the same on your acreage in East Texas, depending of course on what size you're using today?

Well, we've only got seven wells worth of information, so I can tell you we haven't been able to do much work with whether it's better to put it on production on one rate versus another rate as we go through. So that's something on our list to learn, but with only one year of production and seven wells, we just don't have enough information to really give you much thought there. I can tell you our general philosophy, whenever you're doing these wells you have to calculate what the drawdown is bottom hole. And we're going to on any well, wherever it's at, make sure that we don't have significant drawdowns so that you don't have some kind of effort or problems with that. So we're going to do that anyway with what we're doing on our wells. And it certainly is possible you can draw wells too hard on almost any Basin, and that may be what you see going on. There may be some other things, but we just don't have enough information.

I would say also we find very interesting -- I've found that very interesting for some time and we're interested understanding more about the why and what the impacts are of doing that. So we'll hopefully be able to learn some of that from other people's experience.

Very good. Thank you. That's all I have.

Our next question is a follow-up question from the line of Bob Christensen with Buckingham Research.

How should we think about the compression in your midstream as you drill more wells and we need more compression out there or can we run the compression a little harder and these low pressure lines? Where are we at on creating more reserves I guess and the compression story here?

Well, we are putting in compression right now to basically run the entire system at about 90 pounds pressure, and I'm sure over time as the field matures that 90 pound pressure will go down from there. Over the short-term, in the next few years, we do have to add significant compression as we build out the system. So you'll see us continue to invest in compressors, but basically we're trying to do about 90 pounds across the field right now.

So you're at 90 pounds today, generally?

Generally, that's our goal. Depending on how far you are from the compressor station, that might vary up to 30 pounds, but we don't have any that are several hundred pounds let's put it that way.

And you said you'd likely add compression over the next several years?

Well, as we build out the system, we need to continue to add compression.

Every new lateral --

Every new lateral will have a compression with it, and as I said before we're going to invest a couple hundred million dollars a year at least for the next two to three years. So part of that investment is compression and let me just also talk a little bit about our philosophy in compression.

Thank you.

We purchase part of our compression and that will be part of the capital and we lease part of our compression, but the idea of being that as we get out longer in the life of the field, we'll want to own some of that compression just to keep the wells on longer with our control of that compression. So part of what that capital will be -- is going to the compressor, and like I say, part of the other side of it, the leasing side will be caught up in the expense part of it.

Thank you very much.

Our next question is from the line of Joseph Allman at JPMorgan Chase.

Yes, thank you, hi, again. Back to the economics question on the 2.2 Bcfe well. Steve, when you're talking about it getting a PV10 right around $3.90, I think you're probably just talking about the drill and complete costs. But in thinking about the economics of this play, I think you need to factor in other costs, so what are your thoughts there?

It's hard to -- and I'll kind of give you two pieces of that. The two big pieces that you don't count in what I just said was the land cost. Land costs is about $400 an acre, so it's a few thousand dollars per well. It's not a huge number compared to some of the other plays where people paid significant amounts of dollars for the acreage. And then on the midstream side, the allocation of your costs to a well today versus the allocation of the cost to the well in the future is going to be completely different. But today if you just said what's it cost to hook up the wells we have producing today, it's probably in the area of about $150,000 per well. Now remember, you're bringing that line to a pad with a single well or maybe two wells on it, and so in the future, you won't have any cost to hook that up, because you'll just be tying that into a manifold, so that will change over time.

But the compression stuff is in our cost, even the economic cost is our LOE, so we are, I mean, I don't know what we would be missing there that we have in the future except the land costs which Steve touched on.

If you added a portion of the cost of the midstream to allow costs, you would have to also reduce the operating expenses in the economic run from where they are now -- because in the economic runs, one of the cost is the costs of compression as allocated to each well by what it has to pay the midstream Company.

No, I appreciate that, but I guess so -- like shooting seismic for example, seismic you've shot in the past would be a sunk cost. But any seismic you plan to shoot in the future, you would have to allocate that across wells and capitalize G&A as well, things like that?

All of that would be correct. In a reserve report, you are going to have a G&A component, you are going to have the drill and complete costs. But you aren't going to have seismic, you aren't going to have land. And the extent that you pay to lay pipes to something, and in the Fayetteville Shale as I said in the midstream that comes through on the expense side, and some of the other projects for instance some of the stuff we're doing in East Texas we're laying to ourselves or laying to another person, that could come in as capital also that may not pick up completely in the reserve report.

And then just a follow-up, on the 2.2 Bcfe, do you think that's a pretty good representation of the wells you've drilled so far and your PUDs? Is that a representation of what you think the EURs would actually be?

I think it's a good representation of the SEC rules.

Got it. Okay, thank you very much.

We've had reserve revisions based on performance each year that we booked reserves to the Fayetteville Shale. And so those reserves, 2.2 Bcf were based on 3,700-foot lateral. Well today, we're targeting a 4,300-foot lateral and expect that to potentially even increase over time, so we would hope and expect that we would continue to have positive performance revisions as we continue to have more production history on all these areas.

Thank you. Our next question is a follow-up from the line of Michael Scialla with Thomas Weisel Partners. Please go ahead with your question.

Yeah, a couple on the Fayetteville, obviously the 4,300-foot laterals look like they're doing at least 3 Bcf or better. Based on that lateral length, what kind of price do you need to reach your 1.3 PVI?

For a 1.3 PVI, we just need around $4.

Okay, thanks, and then a couple questions on the Haynesville. What were the costs on those most recent wells?

The most recent wells we're averaging in the [2.95], something like that.

No, I'm talking about in the Haynesville.

Oh, Haynesville, I'm sorry.

That would be good by the way.

That would be good. $10 million.

Okay, $10 million, and the improvements you've seen there, has it primarily been just due to lateral length or anything geologically that you've learned that in areas you want to focus there?

Well, as I said really, all we've tested is that central block. We drilled the four corners of the central block -- that's about 30,000 acres, so we haven't done much step outs. You'll see a step out in some of our other acreage in 2010. Stages, I would just say in general, drilling costs are very comparable to what you're going to see, whether it's Louisiana side, Texas side, that direction. We are doing I think on average more stages, more in the 14 plus stage range in our wells and at least what we hear some of the guys on the Louisiana side are eight to 10 stages. And I think that's the difference between somebody quoting an $8 million well and a $10 million well. But we really haven't, except for just playing with the numbers stages and doing some just minor things with the fluid mix, we really haven't done much testing to try and make the wells optimized. Most of what we've been doing this year is just trying to figure out how big an area could be good on so we could go back and do optimization.

Will you be operating any of the 21 to 26 wells you're planning on drilling there this year?

We will. Our most Eastern acreage block that's about 10,000-acres -- we have 100% of that blocked, and we'll be drilling somewhere between three and five Haynesville wells, Haynesville or Middle Bossier wells this year that we'll operate.

And how much cheaper do you expect the middle Bossier to be? Is there much savings there?

It's 400-foot shallower. If you drill the same lateral it's going to be the same price.

Okay, thank you.

The next question is from the line of Rehan Rashid of FBR Capital Markets.

Apologies, don't mean to beat a dead horse here -- but the 2.2 B's, would the presumption be correct that it is the associated development CapEx in the PV10 calculation is not reflective of future synergies like pad drilling and savings from the sand that you'll have on your own?

What you have in the reserve report is just what you've done recently. There's nothing future put into that at all.

Okay, just wanted to confirm that, thank you.

Our next question is from the line of Bob Christensen with Buckingham Research.

Just to follow-up on your midstream, your EBITDA, is that money that is being made in the midstream off of your Company or is it from third parties in the Fayetteville Shale? Just trying to understand the intracompany profits.

Today, that 1.3 Bcf a day that they're gathering, about [100 million] a day is third party.

And on 100 million a day you're making EBITDA of --

No, no, that number is everything. Yes, that is the standalone for the midstream using a gathering charge that is out there, third party gathering charge that everybody else is charging, whoever is gathering gas in the play, so if you stood it alongside by itself that's what it is. Ultimately, we report the segment separately and ultimately eliminate intercompany at the top, so a majority of the EBITDA is related to our E&P segment. However, in the E&P segment fully bears the true LOE for that just like we were third party gathering all of the numbers that Steve was going over with you on the economics and everything else. So if ultimately something is ever done with the midstream, you end up with exact same numbers that we're going you in the E&P segment, it's a true operating expense. And that EBITDA that's generated by the midstream, you really should be looking at that as a multiple of what those things are trading out there. But that is a apples and apples type comparison with a third party MLP type midstream.

Bob, the midstream, another way of saying it, the midstream is set up as a separate entity, in other words it has capital investments, and whosever gas it gathers, it charges for that, so it charges an operating, it charges a cost per Mcf for example. So if it's gathering Chesapeake Gas, it charges them a rate. If it's gathering our own E&P gas, then it charges the E&P Company a rate, and that is important to understand -- at someone else's question back a while ago about reserve calculation, so that cost to gather is a cost that the E&P wells have to bear, X dollars per Mcf in calculating their reserves and. So the financials that we report are as a standalone Company for what you're asking about on its EBITDA.

How much debt would we assign to that or do you internally assign to that operation?

Well, I mean, we don't assign specific debt to any specific entity. It's total corporate debt. We have in total about $1 billion of debt. As you can see, and as we will get even at a little over $5 gas towards the end of this year, we get pretty much cash flow neutral on the EBITDA basis, we're getting closer to that in the midstream and -- but we still probably have a year or so before we'll actually be kind of in a neutral standpoint with midstream. But we have at least as Steve said a couple more years we'll have $200 million to $250 million type investments in midstream and this year I think it's actually $270 million.

One final if I might. What's happening back up in the Overton field? What's production there now and way down from the past?

Well, I think the easy answer in Overton is we haven't drilled there in almost two years and so you're just on a PDP decline. And that doesn't mean that there's a problem with Overton other than the fact that we haven't drilled in the well cost there. We really need $6 gas to drill. There is two horizontal wells we drilled in some of the worst rock that's performing fairly well and we drilled those 1.5 years, so you'll see us go back into Overton and drill more wells in the future, but really you're just seeing a decline.

How fast is the decline annually?

It's roughly 25% at Overton.

A year?

Yes.

Okay, so we're down 50% in two years?

Yes.

Okay. Thank you.

Ladies and gentlemen, we have reached the end of our allotted time for questions. I'd like to turn the floor back over to Mr. Korell for closing comments.

Brad tells me I need to do a perfunctory personal note closing here, so here is my attempt at that. As you know, this will be the last one of these teleconferences for me, as I'll be retiring as an employee of Southwestern Energy at the end of March. I plan to remain on the Board and serve as a non-executive Chairman and have more flexibility with my personal time to pursue new ventures, or I should say adventures possibly. I want to say thank you for letting me live the American dream. Really, looking back at my career, I've been so fortunate to have had opportunities -- opportunities for a great education, opportunities to use my knowledge, skills, and competitive spirit, and the opportunity to participate in an environment of free enterprise and American capitalism. I've been able to be a part of something here at Southwestern that has truly been extraordinary and I've loved almost every minute of it. I'm thankful for all of the people here at Southwestern who have made all of this happen and many of those will be friends for my life. I also want to say thank you for the shareholders who have had the faith in our Company as we have lived through some tough times, and who have been able to celebrate with us through the really good times, which are now. And I want to thank the Board for giving me the opportunity to be at the helm of this fine ship. That concludes our teleconference for today and thanks for joining us.

You may now disconnect your lines at this time. Thank you for your participation.