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Southwestern Energy Company (NYSE:SWN)

Q4 2009 Earnings Call Transcript

February 26, 2010 10:00 am ET

Executives

Harold Korell – Executive Chairman

Steve Mueller – President and CEO

Greg Kerley – EVP and CFO

Analysts

Scott Wilmoth [ph] – Simmons & Company

Jeff Hayden – Rodman & Renshaw

Scott Hanold – RBC Capital Markets

Mike Scialla – Thomas Weisel Partners

Brian Singer – Goldman Sachs

Bob Christensen – The Buckingham Research Group

Rehan Rashid – FBR Capital Markets

Judd Sturdivant [ph] – OCAP Management [ph]

David Heikkinen – Tudor, Pickering, Holt

Joe Allman – JPMorgan

Nicholas Pope – Dahlman Rose

Brian Kuzma – Weiss Multi-Strategy

Dan McSpirit – BMO Capital Markets

Operator

Greetings and welcome to the Southwestern Energy Company fourth quarter earnings 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.

Harold Korell

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 have 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.

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 in 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 continue 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 our industry. This is all pretty amazing when considered just five years ago, when 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 Lime 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.

Steve Mueller

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 in proved developed, down to 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 of our 2009 production at a finding and development cost of $0.86 per Mcf equivalent, including revisions. Excluding revisions, we replaced 561% of our production, had an F&D of $0.91 per Mcf.

Now I’ll 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 lower gas prices. The finding and development cost, 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, including our year-end 2009 reserves, was approximately 2.2 Bcf per well, up from the 1.9 Bcf per well at the end of the year 2008. And based upon current drilling phase, 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. Our 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 the 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 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 feet per day at the beginning of 2009 to approximately 1.2 Bcf a day at year-end.

Recently we’ve had some delays due to operational issues and the colder weather that have caused 25 tier wells to be put on production during the last few months than originally planned. As a result, we have added two additional drilling rigs that would 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 Fayetteville Shale play, 16 are capable of drilling horizontals and six smaller rigs are used to drill the vertical sections of the wells.

In our East Texas operating areas, we had an excellent result, posting production growth of 10% to 34.9 Bcfe, with reserves of 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, we have participated in a total of 77 horizontal wells. Of those, 43 were operated by us and placed on production on average growth initial rate of 9.8 million cubic foot per day. We also kicked off our drilling program targeting the Haynesville and Middle Bossier shales in Shelby and San Augustine counties in 2009 with very good results.

After our first horizontal well production tested at 7.2 million cubic feet per day in the first quarter of 2009, we have drilled four additional wells in the Haynesville Shale, which production tested 13.4, 16.7, and 21.0 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 feet per day.

We are currently completing our sixth Haynesville well, the Red River 620 1-H, and drilling two additional Haynesville wells in the area, the Red River 619 Number 2 1-H and the Owens Number 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 have placed our first Pettet oil well on production. The Acheron 2-H was placed on production in January and 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, three were in progress -- 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 and average remaining lease term of five years and 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 were 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 Number 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 are 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 there are 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 are looking forward to what lies ahead in 2010 and the many years to come.

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

Greg Kerley

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 $522 million or $1.52 per share, excluding $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 to 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 with $750 million in 2009 compared to $814 million in 2008. For the year, we grew our production to 300 Bcf equivalents 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 cycled 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 per 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 field during 2009.

Our general and administrative expenses per unit 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 $2.00 in the prior year. The decline was due to the 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 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 cost and expenses. At December 31, 2009, our Midstream segment was gathering approximately 1.3 billion cubic feet of gas per day, 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 is 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 will actively manage our capital program and make reductions in our 2010 plans.

However, if gas prices rebound during the year, we could increase our planned 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. I will now turn back to the operator who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) Our first question is from the line of Scott Wilmoth [ph] with Simmons & Company. Please go ahead with your question.

Scott Wilmoth – Simmons & Company

Hey, just following up on the flexibility of the CapEx budget. Could you put some magnitude around it, say, on a $4 gas price for 2010? What type of magnitude decrease in CapEx budget would we have? And ultimately what would that do to guidance?

Greg Kerley

Well, if you look at the guidance that we’ve kind of already prepared and sent out publicly in December, there is about a $300 million swing in our cash flow if we were to average $4 versus $5. So (inaudible) our capital program to try to stay fairly in the same range that we expected for our total net volumes for the year.

Steve Mueller

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

Scott Wilmoth – Simmons & Company

So impact on guidance would be minimal?

Steve Mueller

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

Scott Wilmoth – Simmons & Company

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?

Steve Mueller

All those are 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 will 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. You can’t move the equipment. If you can’t move the equipment, you can’t drill as fast. And that’s the combination.

Scott Wilmoth – Simmons & Company

Okay. Thanks, guys.

Operator

Thank you. Our next question is from the line of Jeff Hayden of Rodman & Renshaw. Please go ahead with your question, sir.

Jeff Hayden – Rodman & Renshaw

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

Steve Mueller

Well, I can start by talking about EUR. I believe the EUR is just over 5 Bcf on our wells. We are kind of 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 we have booked in the year. And again, if you think about our acreage position out there, we’ve got a metal block that we call Jebel acreage. If you look at any of our presentation materials, we have now drilled all four corners of that block. So we are feeling comfortable about the acreage. We certainly don’t have that completely booked. We only had booked at the end of the year. It was a total of 30 Bcf for the Haynesville and that included seven proved locations and 10 PUDs for a total of 17 PUD locations.

Jeff Hayden – Rodman & Renshaw

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

Steve Mueller

Well, the rigs that we’re running will drill between 20 and 24 wells this year. It is going to be all in Bradford County. It’s right on top of -- when I say right on top of, within a mile or two of the Stagecoach pipeline. And we have firm on that pipeline today of 20 million cubic foot. We are building that going forward. And that’s the reason we are drilling where we are at, because we do have the capacity on that line to be able to do that.

We will participate probably in another 20 wells. Most of those would probably be -- a little bit maybe in Bradford, but most will be in Susquehanna, and we will have minority interest in those wells, and whatever the operator there is, we will have to take away. So we’re not worried about that portion. Over the next year, we will keep one rig running, and then you will see us build that activity into the future. We will say the one area that will have the less drilling over the next couple of years will be in Lycoming County. That’s more 2012 and beyond where we see much drilling there.

Jeff Hayden – Rodman & Renshaw

All right. Appreciate it, guys.

Operator

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

Scott Hanold – RBC Capital Markets

Thanks. Good morning.

Steve Mueller

Good morning.

Scott Hanold – RBC Capital Markets

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?

Steve Mueller

There were some that -- there is a very small amount. I don’t know, it’s -- additive wells.

Scott Hanold – RBC Capital Markets

Is it fair to say then I think the 387 price at the end of the -- use for your reserves, most of Fayetteville PUDs held up economic?

Steve Mueller

Yes.

Scott Hanold – RBC Capital Markets

Okay, very good. Okay. And when you -- you had mentioned we have two years of PUDs currently booked at this point in time. How do -- I know it's not sort of perfect math, but when you look at how many offsets per PDP, what does that kind of look like?

Steve Mueller

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

Scott Hanold – RBC Capital Markets

Okay.

Steve Mueller

The total number of wells is $1,150 though we have booked PUDs right now.

Scott Hanold – RBC Capital Markets

Okay. And that 2.2 Bcf I guess, you are on your wells. Is that -- I mean, that seems pretty conservative relative to the performance you’ve been seeing. Has there been sort of a difference in some of these newer wells that you’re pouring online where you’re booking at a much higher rate. I know there is a range, but on average, is it pretty clear trend that 2009 adds were significantly higher than prior years?

Steve Mueller

Let me explain how we do the reserves, and I’ll let you kind of 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 are going to drill in the future. And 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, that’s had enough production on it to count. And so if you think about any of these areas and break it up, we have roughly 30 different areas we’d break it up into. Your own 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. We think it’s reflected in our overall reserve numbers.

Scott Hanold – RBC Capital Markets

Okay. Now I got it. That makes it clear. And one last question if I could. PV-10 value, I’m sorry if I missed that, what was your year-end PV-10 value? And if you have that between the PDPs and the PUDs, that would be great.

Steve Mueller

I don’t have that right here. Scott, we will look it up and give -- answer that one in a while.

Scott Hanold – RBC Capital Markets

All right. Appreciate it. Thanks.

Operator

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

Mike Scialla – Thomas Weisel Partners

Good morning guys. It sounds like you'll probably 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 PV-10.

Steve Mueller

I can tell you, we haven’t.

Mike Scialla – Thomas Weisel Partners

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

Steve Mueller

As far as the Pettet goes, we are trying to figure out how big it could be. Right now, there are about six wells that Cabot has drilled. We are on our first well and are participating in the other two I talked about. And it looks like if you’ve 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 might be a 100 type wells -- 100 wells that you have to drill out there. But it’s way early. There could be if we drill four or five more wells and six more wells we have to drill.

So we just have to figure that out from that standpoint. And then as far as targeting new ventures, which are targeting oil or gas, if you think about any of these plays that are new, and we just talked about the type and we are going to spend five years since the time of Fayetteville. From the time you come up with the idea, 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 are doing is looking for the best 1.3 PVI projects. And if they have the oil, there would be oil. If they have the gas, then the gas.

Mike Scialla – Thomas Weisel Partners

Thanks, Steve.

Operator

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

Brian Singer – Goldman Sachs

Thank you. Good morning. Going back to your comments on capital allocation, given that lower gas price is here. Can you talk more about the decision to add two rigs to make yourself whole on Fayetteville drilling? And I need to talk a little bit more about the Midstream commitments and how that allows or does not allow for flexibility in Fayetteville activity.

Steve Mueller

Let me start with the Midstream first. Our guidance for the year, the Midstream is actually a little bit higher capital program that we had last year in Midstream. And we will be drilling a large number of wells in kind of the eastern -- toward eastern central area to hold on the old acreage. And we will be 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 then it will give us flexibility into the future. And we still got probably at least two more years of that $250 million to $280 million of your capital to really build out most of the program we have. So they are just continuing to do that, 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 the wells just the hold acreage.

The other wells are still trying to learn things. And as we down-space and do closer spacing, we are learning that certain areas look like they are going to be a little tighter spacing and another is going to be a little wider spacing. And we need to get that learning down 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 a learning part of it. We had the opportunity to add two rigs early this year on a relatively short-term contracts. Both of those rigs will expire before the end of the year. And we thought it was a good bet, going back again the gas price is $4. You will see us drop those rigs later in the year. If it’s $6, we’ve gone in more team and in shape that we can accelerate one in the next year. So the game is a good bet and it helps us learn at the speed we want to learn it.

Brian Singer – Goldman Sachs

Thank you. That’s really helpful. And then secondly, on the Haynesville, Bossier and Marcellus, did you think about those assets as keepers or would you consider a joint venture to either accelerate activity in our group of balance sheet.

Steve Mueller

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 by just moving rigs around or moving rigs up or down. So I don’t think right now thinking about joint ventures anywhere, whether at Haynesville or anything else. We have stated in the past that and what we’ve stated here again today that if you are running kind of a quality of our projects, both I think what we have in Pennsylvania and Fayetteville worked with $4 numbers on the gas. When you get into East Texas, you’re going to need to have five on most of what’s going on there. And that’s why we said it was for our gas, would adjust the East Texas down.

Harold Korell

Yes. 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 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 -- and as Steve said, we have the ability to fund and hold this acreage, and we don’t find ourselves in a financial squeeze here. So we’re not compelled to do any of those kinds of things right now.

Brian Singer – Goldman Sachs

Thank you, Harold.

Operator

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

Bob Christensen – The Buckingham Research Group

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

Steve Mueller

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

Bob Christensen – The Buckingham Research Group

Okay. That’s all I have. Thank you.

Operator

(Operator instructions) Our next question is from the line of Rehan Rashid with FBR Capital Markets. Please go ahead with your question.

Rehan Rashid – FBR Capital Markets

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

Steve Mueller

Everything we’ve 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 lengths in 2010, our overall cost would be down. And I think we did a press release at the end of the year, talked about it, $2.75 million average.

Rehan Rashid – FBR Capital Markets

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?

Steve Mueller

Well, we are working on all kinds of things. And two, the rigs are running right now. RAC rigs that have some of the characteristics, and one of them has, I think, most of the characteristics we want to use on pad drilling. And we are learning what those might be able to do for us. So we are continuing to work on the drilling side of it. Completion side, we are averaging between 12 and 14 frac stages, but I can tell you we are playing with the 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 are some cost savings in there.

And then as you mentioned, we are not pad drilling yet. In 2010, we will actually grow fewer wells per pad than we did in 2009. And you won’t see us really start ramping up until 2011. We were doing pad drilling. There will be a lot of synergies on the pad drilling that will put downward pressure on that cost. So there are certainly things we are working on, but I don’t think any one of them is as much as the $130,000 to $150,000 we have in sand.

Rehan Rashid – FBR Capital Markets

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

Steve Mueller

The average lateral length of the PUDs that are in our reserve reports, 3,700 feet.

Rehan Rashid – FBR Capital Markets

3,700 feet. Okay, good. And the negative reserve revisions, what vintage wells would these be, just trying to think through?

Steve Mueller

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

Rehan Rashid – FBR Capital Markets

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

Steve Mueller

Yes. And let me just tell you we talked before about the fact -- I think we released some information that what we’re doing of somewhere around 12, 13 at very tight spacings. We’ve now increased that this year. We will end up well over 20 at tighter spacing. And the reason for that is we are giving mixed results. We’ve had about half of the tighter spacing work very well and give us a 1.3 PVI and would drill about half, those have question marks on. So we’re going to have to expand that program. That goes back to Brian’s questions earlier about morning catch up on those 25 wells. We’re just getting the mix results that tells you must be getting close. But we got to just give some more information so we can learn more about it.

Rehan Rashid – FBR Capital Markets

Okay, okay. I think that is it. Thank you.

Greg Kerley

Let me jump in here. Scott Hanold had asked a question on what our PV-10 was on our reserve report for the Fayetteville Shale, for both the PDP and PUD. The PDP, this is at the 387 NYMEX average that we had and then there is going to be a basis differentials lower than that. But the PDP was $2.2 billion. The PUDs were $23 million. So you can see that PUDs are just around the PV-10 mark that the 387 minus roughly $0.30 basis differentials.

Operator

Our next question is from the line of Judd Sturdivant [ph] of OCAP Management [ph]. Please go ahead with your question.

Judd Sturdivant – OCAP Management

Hi, guys. Congratulations on another record setting year. 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 ‘08 and 2010 expectations? Thanks.

Steve Mueller

I will talk a little bit about the cost 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 that we own 11 of the bigger rigs that are running in the Fayetteville Shale. One of the reasons we own our own sand mine is that the only way you could really hedge those costs over a long period of time. And both of those will 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 and we are trying to lengthening that out significantly right now to kind of control those kinds of costs. And then on pumping service side, it really just depends on what part of the country you are in, how much pressure you’re getting on a pumping service. Certainly you’re seeing cost go up in the Haynesville. And in the Marcellus, just because the equipment is not there yet, we are seeing some upward pressure. The other side of that equation for us is it is worth 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 drill a 2,700-foot lateral. Today it’s $2.9 million to $3.0 million to drill 4,300-foot lateral. And we are working hard with whatever we do on the learning side that we can offset any of those kinds of costs we’ll have going forward.

Judd Sturdivant – OCAP Management

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

Steve Mueller

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

Judd Sturdivant – OCAP Management

Great, thanks.

Greg Kerley

Just to follow up on the basis question, we’ve seen basis continue to tighten. I mean, in our current guidance that 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.

Steve Mueller

And let me jump in. We do have a 140 Bcf hedged at that low number. So we know at least for the near-term, we will 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 are at, you can almost get the best price that’s on your local market as opposed to trying to get to the East Coast.

Operator

Thank you. Our next question is from the line of David Heikkinen Tudor, Pickering, Holt. Please go ahead with your question.

David Heikkinen – Tudor, Pickering, Holt

Good morning. Just had a question on your 2009 proved reserve category, summary of net acreage and then 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 --?

Steve Mueller

Yes. It has no producing wells on it, correct.

David Heikkinen – Tudor, Pickering, Holt

And then the delta between those, that’s not that that acreage is fully developed. Basically we should just think about you’ve booked a 1,150 PUDs to the Fayetteville. And then all 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?

Steve Mueller

That is correct. And I’ll use the Fayetteville Shale as an example. In Fayetteville Shale, if you drill one well on a 640 acres spacing and put it on production, that holds the whole 740. That would make it developed acreage. Well, then you come back later and our 600-foot spacing we are talking about would be at least 10 wells total. So we’d have to drill nine other wells on its section. Even though it was an acreage, it’s counted as developed acreage.

David Heikkinen – Tudor, Pickering, Holt

Okay. Just making sure. That's helpful. And then you answered the question of kind 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, kind of the same ratio? Or is it less sensitive because there is future development?

Steve Mueller

Those are PUDs for the most part. The PUDs in East Texas and Arkoma need a little bit higher gas price. But to put it in perspective, 99% of our PV value as a company comes from proved developed. So there is almost nothing in the proved undeveloped. It’s all 10%, 8% type discount numbers.

David Heikkinen – Tudor, Pickering, Holt

Okay. Everything else has been answered, thanks.

Operator

Thank you. Our next question is from the line of Joe Allman with JPMorgan. Please go ahead with your question.

Joe Allman – JPMorgan

Thank you. Good morning, everybody.

Steve Mueller

Good morning.

Joe Allman – JPMorgan

I think you answered this in a way, but when you talked about the PUDs being economic at 387, you booked your reserves based on PV-0 as opposed to PV-10, and at 387, most of your Fayetteville Shale probably isn't economic on a full cycle basis, is that correct?

Steve Mueller

The 2.2 Bcf wells is just about economic at 390 -- 387 to 390. So I want to say economic is your PV-10. To get our 1.3 PVI, we need the $4.30 range at 2.2 Bcf average. Now again, that’s the average of all we have out there. We’ve got sound PUDs where they are significantly higher than that. We’ve got some that are lower than that. Those lower ones obviously were booked at something, PV-0 or greater.

Joe Allman – JPMorgan

Got you. And then when you gave the PV-10 -- the PDP PV-10 of $2.2 billion, I think, Steve, you said that was just the Fayetteville or --?

Steve Mueller

That was just the Fayetteville.

Joe Allman – JPMorgan

Okay. Do you have the numbers for the whole company or --?

Steve Mueller

I’m sorry. That was total. I’m sorry. The Fayetteville, if we go back to this, the number I gave you before, the 2.2 is the total company. The Fayetteville was $1.9 billion basically for the PDP and – 1.8, 1.9 for PDP -- for proved, I’m sorry.

Joe Allman – JPMorgan

Okay. And what about for the PUDs?

Steve Mueller

$39 million for the PUDs.

Joe Allman – JPMorgan

Okay, got it. So that suggests that --

Steve Mueller

So the difference, 39 or 23, so there was -- whatever that is, $16 million of less than PV-10.

Joe Allman – JPMorgan

Okay, got it. Okay, thank you very much.

Operator

Our next question is from the line of Nicholas Pope with Dahlman Rose. Please go ahead with your question.

Nicholas Pope – Dahlman Rose

Good morning, guys.

Steve Mueller

Good morning.

Nicholas Pope – Dahlman Rose

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

Steve Mueller

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

Nicholas Pope – Dahlman Rose

And then 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 or is that still --?

Steve Mueller

We’ve got information on eight. Some of that information doesn’t have a lot of production arm. We’ve got information on eight. And I can tell you that on those eight, there is four that gives very good economics, well above our 1.3 PVI. There is a couple that are bouncing around and may make a 1.3 PVI. And there is a couple that aren’t good at all.

Nicholas Pope – Dahlman Rose

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?

Steve Mueller

There really isn’t anything to be ready into it anymore than -- companies are getting beat up for corporate governance type things, and this is one of those corporate governance issues. You will see that we’ve done a couple different things as a company. One of them is we just decided it was a worthy 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. We tweaked it a little bit. And one of those tweaks was we decided we don’t need the rights plan.

Nicholas Pope – Dahlman Rose

All right. That’s very helpful. That's all I had.

Operator

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

Brian Kuzma – Weiss Multi-Strategy

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

Operator

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

Dan McSpirit – BMO Capital Markets

Gentlemen, good morning and thank you for taking my question. Certain operators in the Haynesville, at least on the North Louisiana side have experiment within an even reduced the choke size, in which they flow the wells. Can you comment on the benefit 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?

Steve Mueller

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 a one rig versus another rig 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 (inaudible). And we are going to, on any well, wherever it’s at, make sure that we don’t have significant draw-downs so that you don’t have some kind of effort or problems with that. So we’re going to do that anyway with whatever we are doing on our wells. And it certainly is possibly you can drill wells too hard on almost any basin. And that may be what you see going on and maybe some other things, but we just don’t have enough information.

Greg Kerley

Yes. I mean, I would say also, we find it very interesting. I’ve found that very interesting for some time, and we are interested in understanding more about the lie and what the impacts are of doing that. So we will hopefully be able to learn some of that from other people’s experience.

Dan McSpirit – BMO Capital Markets

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

Operator

Our next question is a follow-up question from the line of Bob Christensen with The Buckingham Research. Please go ahead with your question.

Bob Christensen – The Buckingham Research Group

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 hard and these well pressure lines -- where are we at on creating more reserves, I guess? And the compression story here.

Steve Mueller

Well, we are putting compression right now to basically around the entire system about 90 pounds pressure. And I’m sure, over time as feel matures at 90-pound pressure, we will go down from there. Over the short-term. I mean, the short-term and an extra year, we do have to add some significant compression as we build out the system. So you will see us continue to invest in compressors. But basically we’re trying to do about 20 pounds across the field right now.

Bob Christensen – The Buckingham Research Group

You are at 90 pounds today, generally and --?

Steve Mueller

Generally. Yes, that’s our goal depending how far you’re offering compressor station. Had that might very up to 20 pounds. But we don’t have any that are several hundred pounds. Let’s put it that way.

Bob Christensen – The Buckingham Research Group

And you said like the add compression over the next several years.

Steve Mueller

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

Bob Christensen – The Buckingham Research Group

Every new lateral has to have a --

Steve Mueller

Every new lateral is going to have compression with it. And as I said before, we are going to invest couple of $100 million 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 philosophy and compression.

Bob Christensen – The Buckingham Research Group

Thank you.

Steve Mueller

We purchased part of our compressions, and that would be part of the capital and we lease forever compression. The idea being that as we get up long and life, we are going to want to own some of that compression just to keep the wells on longer, with our control with our compression. So part of what that capital will be is going to compressor, like, say, part of the other side of it, the leasing side will be caught up in the next month.

Bob Christensen – The Buckingham Research Group

Thank you very much.

Operator

Our next question is from the line of Joe Allman with JPMorgan Chase. Please go ahead with your question.

Joe Allman – JPMorgan

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 PV-10 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?

Steve Mueller

It’s hard to -- I'll try to give you two pieces to that. The two pieces -- the big of it, you don’t calc what I just said was the land costs. Land cost 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 size, that -- the allocation of your costs to a well today versus the allocation of costs to a well in future is going to be completely different. But today, if you just said what the cost to hook up the wells that we haven’t producing today, it’s probably in order of about $150,000 per well. Remember, you’re bringing that line to a patent 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. And so that will change over time.

Greg Kerley

But the compression stuff is in our cost -- in our economic costs as our LOE. So we are -- I mean, I don’t know what we would be missing there that we took out in the future, except the land costs, which Steve touched on.

Harold Korell

If you added a portion of the cost of the Midstream to a well cost, 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 costs is the cost of compression as allocated to each well by what it has to pay the Midstream company.

Joe Allman – JPMorgan

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

Steve Mueller

All of that would be correct.

Joe Allman – JPMorgan

Okay, got you. All right.

Steve Mueller

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’re not going to have seismic. You’re not going to have land. And to the extent that you pay to lay pipes or something, in the Fayetteville Shale, the size of Midstream, that comes from 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 as capital. Also they may not pick up completely in reserve report.

Joe Allman – JPMorgan

Got you. 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?

Steve Mueller

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

Joe Allman – JPMorgan

Got it. Okay. Thank you very much.

Greg Kerley

And we’ve had reserve revision or revisions based on performance each year that we booked reserves to the Fayetteville Shale. And so those reserves, 2.2 Bcf, were based upon 3,700-foot lateral. But today our -- 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 and continue to have positive performance revisions as we continue to have more production history on all these areas.

Operator

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

Mike Scialla – Thomas Weisel Partners

Yes. 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?

Greg Kerley

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

Mike Scialla – Thomas Weisel Partners

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

Greg Kerley

The most recent wells were averaging in the 2.95, something like that.

Mike Scialla – Thomas Weisel Partners

No, I'm talking about in the Haynesville.

Greg Kerley

Oh, Haynesville, I’m sorry. The --

Mike Scialla – Thomas Weisel Partners

(inaudible) by the way.

Greg Kerley

Yes, that would be good. $10 million.

Mike Scialla – Thomas Weisel Partners

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

Steve Mueller

As I said earlier, all we’ve tested is at central block, kind of drilled the four corners at central block. We have about 30,000 acres. So we haven’t done much step-out. You will see a step-out in some of our other acreage in 2010. Stages, I would just say in general, growing costs are very comparable to what you’re going to see, whether it’s the Louisiana side, Texas side, in that direction.

We are doing, I think, on average more stages on the 14-plus stage range on our wells. And at least what we hear some of our guys in Louisiana cited are eight to 10 stages. And I think that’s the difference between somebody quoted an $8 million and a $10 million. But we really haven’t -- except we are just playing with the number of stages and doing just some 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 done this year is just trying to figure out how big an area could be good on so that we can go back and get optimization.

Mike Scialla – Thomas Weisel Partners

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

Steve Mueller

We will. There is our most eastern acreage block that’s got 10,000 acres. We have 100% of that block. And we will be drilling three to -- somewhere between three and five Haynesville wells -- Haynesville or Middle Bossier wells this year that we will operate.

Mike Scialla – Thomas Weisel Partners

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

Steve Mueller

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

Mike Scialla – Thomas Weisel Partners

Yes, okay. Thank you.

Operator

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

Rehan Rashid – FBR Capital Markets

Apologies, don't mean to beat a dead horse here. But the 2.2 Bs, would the presumption be correct that it is the associated development CapEx in the PV-10 calculation is not reflective of future synergies like pad drilling and savings from the sand that you'll have on your own?

Steve Mueller

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

Rehan Rashid – FBR Capital Markets

Okay. Just wanted to confirm that. Thank you.

Operator

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

Bob Christensen – The Buckingham Research Group

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 intra-company profits.

Steve Mueller

Today about -- the 1.3 Bcf a day that they are gathering, about 100 million a day is third party.

Bob Christensen – The Buckingham Research Group

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

Steve Mueller

No, no, no. That number is for the whole -- that's for everything.

Greg Kerley

Yes, that is the -- that's the standalone for the Midstream using a gathering charge that is out there, third-party gathering charge that everybody 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 segments separately and ultimately eliminate inter-company at the top. So majority of the EBITDA is related to our E&P segment. However, in the E&P segment fully bears true LOE for that just like we were a third-party gatherer and all of the numbers that Steve was going over with you on the economics and everything else. If ultimately something is ever done with the Midstream, you end up with exact same numbers that we’re showing you right now in the E&P segment. It’s the 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. That is an apples-and-apples type comparison with a third-party MLP type midstream.

Harold Korell

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 that gathers, it charges for that. So it charges in operating -- charges the 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 -- someone else’s question back a while ago about reserve calculation. So that cost together is a cost that the E&P wells have to bear X amount -- X dollars per Mcf in calculating their reserves. And so the financials that we report are as a standalone company for what you are asking about on its EBITDA.

Bob Christensen – The Buckingham Research Group

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

Greg Kerley

I mean, we don’t sign specific debt to any specific entity. It’s total corporate debt. We have, in total, about $1 billion of debt. As you can see, 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 are getting closer to that in the Midstream, but we still probably have a year or so before we will actually be kind of in a neutral standpoint with Midstream. But we have at least, as Steve said, a couple more years that we will have $200 million, $250 million type investments in Midstream. In this year, I think it’s actually $270 million.

Bob Christensen – The Buckingham Research Group

One final if I might. What's happening back up in the Overton Field? Let’s go back and -- what's production there now and way down from the past? I mean, with such a --

Steve Mueller

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 is a problem with Overton. In fact, we haven’t drilled and the well cost there, we really need $6 gas to drill. There is two horizontal wells we drilled in some of the worst rocks that’s performing fairly well, and we drilled those a year and a half ago. And so you will see us go back into Overton and drill some more wells in the future, but really you’re just seeing the decline.

Bob Christensen – The Buckingham Research Group

How fast is the decline annually?

Steve Mueller

It’s roughly 25% in Overton.

Bob Christensen – The Buckingham Research Group

A year?

Steve Mueller

Yes.

Bob Christensen – The Buckingham Research Group

Okay. So we are down 50% in two years.

Steve Mueller

Yes.

Bob Christensen – The Buckingham Research Group

Okay. Thank you.

Operator

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

Harold Korell

Mr. Korell, I think.

Steve Mueller

Yes, Mr. Korell is going to give closing comments.

Harold Korell

Brad tells me I need to do a perfunctory personal note closing here. So here is my attempt at that. As you know, this would be the last one of these teleconferences for me, as I will 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, add ventures possibly.

I want to say thank you for letting me live the American dream, really. Looking back at my career, I have been so fortunate to have opportunities, opportunities for a great education; opportunity to use my knowledge, skills and competitive spirit; and the opportunity to participate in an environment of free enterprise and American capitalism.

I have been able to be a part of something here at Southwestern that has truly been extraordinary, and I have loved almost every minute of it. I’m thankful for all the people here at Southwestern who 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.

Operator

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

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Source: Southwestern Energy Company Q4 2009 Earnings Call Transcript
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