8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): April 28, 2009

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation)

1-08246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 125, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)

(281) 618-4700

(Registrant's telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

       o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

The information in this Report, including the exhibit, is being furnished pursuant to Item 7.01 of Form 8-K and General Instruction B.2 thereunder.  Such information shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

SECTION 7 -  REGULATION FD

Item 7.01 Regulation FD Disclosure.

On April 28, 2009, Southwestern Energy Company hosted a telephone conference call for investors and analysts.  The teleconference transcript is furnished herewith as Exhibit 99.1.

Exhibits.  The following exhibit is being furnished as part of this Report.

Exhibit Number	Description
99.1	Teleconference transcript for April 28, 2009 telephone conference call for investors and analysts.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SOUTHWESTERN ENERGY COMPANY
Dated: April 29, 2009	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Teleconference transcript for April 28, 2009 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Company

Q1 2009 Earnings Conference Call

Tuesday, April 28, 2009

Officers

Harold Korell; Southwestern Energy; Chairman and CEO

Steve Mueller; Southwestern Energy; President

Greg Kerley; Southwestern Energy; CFO

Analysts

Scott Hanold; RBC Capital Markets; Analyst

David Heikkinen; Tudor, Pickering & Holt; Analyst

Rehan Rashid; Friedman Billings Ramsey Group; Analyst

Joe Allman; JP Morgan; Analyst

Tom Gardner; Simmons & Co.; Analyst

Gil Yang; Citi; Analyst

Brian Singer; Goldman Sachs; Analyst

David Snow; Energy Equities Incorporated; Analyst

Robert Christensen; Buckingham Research Group; Analyst

Mike Scialla; Thomas Weisel Partners; Analyst

Ray Deacon; Pritchard Capital; Analyst

Brian Kuzma; Weiss Multi-Strategy; Analyst

Jack Aydin; Keybanc Capital Markets; Analyst

Marshall Carver; Capital One Southcoast; Analyst

Jeff Hayden; Rodman & Renshaw; Analyst

Omar Jamma; Owl Creek; Analyst

David Snow; Energy Equities, Inc.; Analyst

Presentation

Operator: Good day, and welcome to the Southwestern Energy Company First Quarter Earnings Teleconference. At this time, I would like to turn the conference over to the Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold Korell: Good morning. Thank you for joining us. With me today are Steve Mueller, President of Southwestern Energy, and Greg Kerley, our Chief Financial Officer.

If you've not received a copy of yesterday's press release regarding our first quarter 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 Securities and Exchange Commission.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Well, to begin with on this report, we had a very productive first quarter despite the efforts -- or the effects of the recent decline in natural gas prices.

Our production from the Fayetteville Shale continues to climb as we move up the learning curve in the play. Our gross operated production from the play reached approximately 850 million cubic feet per day at the end of the first quarter, compared to approximately 400 million cubic feet per day around this time last year.

While we feel confident that natural gas prices will be higher for the longer term, the price of gas has fallen approximately 35% from year-end 2008, thus causing a non-cash impairment of our oil and gas properties.

As a result of the continuing low commodity price environment, we are reducing our planned capital program for 2009 by an additional $100 million, down to $1.8 billion, which is approximately flat with our 2008 capital investments.

The important thing to know is that commodity prices move in cycles, and with the decreased drilling activity in our industry, we are now positioned for an upturn in commodity prices. With our growing production volumes and financial flexibility, Southwestern is well positioned to benefit.

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'll be available for questions.

Steve Mueller: Thank you, Harold.

Good morning. During the first quarter of 2009, we produced 63.9 Bcfe, up 64% from first quarter of 2008. Our Fayetteville Shale production was 50.2 Bcf, more than double the 23.6 we produced in the first quarter of 2008.

We produced 7.8 Bcfe from East Texas and 5.8 Bcfe from our Conventional Arkoma properties.

As we announced yesterday, we are reducing our expected 2009 capital investment by approximately $100 million to $1.8 billion due to the continued low natural gas prices. To achieve this capital reduction, we are now planning to exit 2009 down six rigs -- four in our Fayetteville Shale play and two in other producing areas.

Due to our continued strong production performance, partially offset by our reduced capital budget, we now estimate that our full-year 2009 production will range from 289 to 292 Bcfe, up from 280 to 284 Bcfe.

In the first three months of 2009, we invested approximately $450 million in our Exploration and Production business activities and participated in drilling 190 wells. Of this amount, approximately $366 million, or 81%, was for the drilling wells.

Additionally, we had invested $51 million in our Midstream segment almost entirely in the Fayetteville Shale.

In the first quarter of 2009, we invested approximately $416 million in our Fayetteville Shale play, including both our E&P and Midstream activities. At March 31, our gross operated production rate was approximately 850 million cubic foot per day, up from 750 million cubic foot per day in mid-February.

During 2008, the majority of our gas from the Arkoma Basin was moved to markets in the Midwest, including through the Fayetteville Lateral portion of the Texas Gas Transmission, or our Boardwalk Pipeline, which was placed in service on December 24.

On April 1, the Greenville Lateral portion of that Boardwalk Pipeline was placed in service, and we began transporting a portion of our gas to Eastern markets.

On March 31, our Midstream segment was gathering approximately 920 million cubic foot per day through 890 miles of gathering lines in the Fayetteville Shale, up from approximately 470 million cubic foot per day a year ago.

In April 2009, Texas Gas announced that there would be a - --temporary reductions on the Fayetteville Lateral due to various activity, including maintenance and pipeline inspection. The exact completion dates of these activities is unknown, but it is expected to be complete by the end of the third quarter.

As a result, transportation of the Fayetteville Lateral as of April 24, 2009 was approximately 700 million cubic foot per day -- or BTU per day. Our capacity was approximately 500 million BTU per day to Bald Knob, Arkansas, including 365 million BTU per day to Lula, Mississippi. We expect that the remainder of our Fayetteville Shale production will continue to be transported in other pipelines to Midwest markets until these issues are resolved.

We currently have 19 rigs running in the Fayetteville's play, 15 that are capable of drilling horizontal wells and four smaller rigs are used to drill the vertical portion of the wells.

As I mentioned previously, we're currently planning on releasing four rigs in the Fayetteville Shale play area this year. This decrease in rig count means that we now expect to participate in approximately 600 gross wells in 2009 rather than our original plan of 650 wells. This is approximately the same number of wells that we drilled during 2008.

Since 2007, the continuous improvement of our completion practices have resulted in fairly steady quarter-over-quarter improvements in average initial production rates of operated wells placed on production. The significant increase in average initial production rates for the fourth quarter of 2008 and subsequent decrease for the first quarter of 2009 primarily reflected the impacts in the delay in the Boardwalk Pipeline.

Initial rates were higher in all the delayed wells because wells were shut in for a longer period of time before being placed on production.

In addition, we generally placed wells with the highest initial rates on production first throughout the fourth quarter of 2008. As a result, the remaining backlog of delayed wells that were placed on production in the first quarter of 2009 generally had lower rates, particularly during January and February.

Wells that were placed on production in January and February of 2009 had average initial production rates of 2,806 Mcf per day and 2,749 Mcf per day, respectively, while wells placed on -- during March 2009 had average initial production rates of 3,375 Mcf per day. For the month of April, through April 15, we have placed 25 wells on production at an average initial rate of 3,763 Mcf per day.

We expect that our average completed well cost in 2009 will be approximately $2.9 million per well as lower oil field services costs are projected to more than offset higher costs associated with the larger completions and longer laterals.

Our first quarter wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet, and average time to drill to total depth of 12 days from re-entry to re-entry.

Because of the continued outperformance in our front-end loading of our drilling in our Fayetteville Shale play, we expect production here to be between 238 and 240 Bcfe in 2009. This is up from our previous guidance of 229 to 232 Bcfe.

I'll now move on to our two newer areas, the Haynesville Shale and the Marcellus Shale. The first horizontal well in our 50/50 joint venture was a private company targeting the Haynesville/Bossier Shale and the Shelby in San Augustine County, Texas.

The Red River 877 #1 reached total depth in the fourth quarter of 2008. This well, which had a completed lateral length of 2,718 feet was production tested at a rate of 7.2 million cubic feet per day in the first quarter of 2009 and is currently producing approximately 3 million cubic foot per day.

The second horizontal well, the Red River 164 #1, has reached total depth with a 3,818-foot lateral and is expected to be completed and tested in the second quarter.

Pending further results from these wells, we may invest more capital in the Haynesville/Bossier Shale play than previously planned.

We currently hold approximately 17,350 net acres in the Texas Joint Venture and a total of 50,110 net acres that we believe may be prospective in the Haynesville/Bossier Shale.

In the Marcellus Shale, we currently have approximately 138,600 net acres in Northeast Pennsylvania, where we believe the shale is prospective.

During 2008, we drilled our first four wells here, including our first horizontal well in our acreage in Bradford and Susquehanna County. During the first quarter, we increased our position in the Marcellus by approximately 23,900 acres.

Finally, we participated in drilling nine wells in the Conventional Arkoma Basin and 11 wells in East Texas during the first three months of 2009. Nine of the East Texas wells are James Lime horizontals.

Production from our Arkoma and East Texas properties were 5.8 and 7.8 Bcfe, respectively, for the first three months of 2009, compared to 5.9 and 8.1 Bcfe for the first three months of 2008.

In summary, we continue to have solid results in our E&P and Midstream businesses, and we expect continued strong results in the remainder of 2009, as demonstrated by our increase in production guidance.

We have decided to reduce our capital budget by approximately $100 million as we continue to focus on adding value during this period of reduced product prices. As Harold mentioned, when commodity prices rebound, we'll be well positioned, both financially and operationally, as a growing low-cost leader.

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

Greg Kerley: Thank you, Steve, and good morning.

As you've seen from our press release, we had a very good first quarter despite the significant drop we've experienced in natural gas prices.

For the first quarter of 2009, we reported a net loss of $432.8 million, or $1.26 a share, including $558 million after-tax ceiling test impairment of our oil and gas properties.

The significant decline in gas prices from $5.71 per MMBtu at December 31, 2008 for Henry Hub Natural Gas down to $3.63 at March 31 led to the ceiling test impairment.

Excluding the non-cash impairment, we recorded earnings of $125.5 million, or $0.36 a share, which was 15% increase over the prior-year period.

Cash flow from operations before changes in operating assets and liabilities was up 31% to $372.6 million, as our production growth more than offset lower realized natural gas prices.

Our average realized gas price during the first quarter was $5.94 per Mcf, 23% lower than our average price a year ago.

Our commodity hedge position increased our average realized gas price by $2.13 per Mcf in the first quarter, which helped us offset some of the effects of lower spot market prices and widening location market differentials or basis that occurred during the quarter.

We currently have approximately 47% of our 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf.

We also have basis protected on approximately 131 Bcf of our remaining 2009 expected gas production through hedging activities and sales arrangements at a differential to NYMEX gas price of approximately $0.25 per Mcf. Our detailed hedge position is included in our Form 10-Q that was filed this morning.

Operating income for our E&P segment was $179.9 million in the first quarter of 2009, excluding the impairment charge, up from $165.7 million in the first quarter of 2008. The increase was driven primarily by the 64% growth in our production volumes, which more than offset the decline in our average realized gas price and higher operating costs and expenses.

Our lease operating expenses per unit of production were $0.78 per Mcf in the first quarter of 2009, compared to $0.77 for the same period in 2008. A modest increase was the result of higher per-unit operating costs associated with the Company's Fayetteville Shale operations, partially offset by the impact that lower natural gas prices had on the costs of compressor fuel in the first quarter of 2009.

General and administrative expenses per unit of production were $0.31 per Mcf in the first quarter of 2009, down from $0.42 for the same period in 2008. The decrease was primarily due to the effects of our increased production volumes, which more than offset increased compensation and related costs associated with the expansion of our E&P operations.

Taxes, other than income taxes, were $0.13 per Mcf in the first quarter of 2009, down from $0.16 for the same period in 2008 due to changes in severance and ad-valorem taxes that primarily resulted from the mix of our production volumes and lower commodity prices.

In total, our per-unit cash operating costs and expenses declined 10% compared to the prior-year period.

Our full cost pool amortization rate dropped to $1.82 in the first quarter, down from $2.30 per Mcf in the prior year. The decline was due to the combined effects of our sales of oil and gas properties during 2008, the proceeds of which were credited to the full cost pool and our low finding and development costs.

As a result of the ceiling test impairment charge in the first quarter, we expect that our amortization rate going forward, with all other factors remaining constant, will be reduced by between $0.30 and $0.40 per Mcf. Operating income for our midstream servicing segment grew significantly in the first quarter of 2009 to $27.4 million, up from $10.2 million in the same period of 2008. The increase was primarily due to the higher gathering revenues and an increase in the margin from our marketing activities, partially offset by increased operating costs and expenses.

We ended the first quarter with approximately $80 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility, and our debt-to-capitalization ratio was 25% even after the ceiling test impairment charge. Continuing low gas prices have impacted our projected cash flows for 2009, and as a result, we've reduced our planned capital investments by approximately $100 million to end the year with approximately the same debt level as we originally planned. We believe we are very well positioned to weather the current low commodity price environment with our strong balance sheet and financial flexibility.

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

Questions and Answers

Operator: Thank you. (OPERATOR INSTRUCTIONS.) We'll go now to Scott Hanold of RBC Capital Markets.

Scott Hanold: Good morning.

Harold Korell: Good morning.

Scott Hanold: When--if we look at that impairment of $900 million, could you give a little bit of color on that, talk about was it some of the PUDs that were impaired, or was it more of a tail?

Steve Mueller: On just a general comment, it's part of the full cost pool. But your PUDs are always going to have--because they have capital against them--are always going to have worse economics than PDPs. So, on the reserve side, any kind of cuts over there would have been on the PUD part of it. But remember, the impairment's at full cost pool, so there's a lot of things that go into it.

Scott Hanold: Okay, thanks. Appreciate the color. And I guess for my second question, you guys obviously trimmed the CapEx budget, but are showing just tremendous growth and it looks like productivity is the key driver here. How do you kind of think about production growth at--when gas is hanging around the $3 to $4 level? I know some of your peers have curtailed productive rates on individual wells. Is that something you all would consider? Kind of how do you think about it?

Harold Korell: Well, the first place to begin on that is how do we feel about producing at higher rates and lower prices? It feels like producing more and enjoying it less. We'd like to see prices higher. But on the other hand, we are fortunate that we're experiencing the improvements we are in our activities in the Fayetteville Shale. So the growth is a good thing. Steve, you may want to make more--.

Steve Mueller: --Yes. I think there's two parts to that. Part of it was what about curtailing or something to do with--that way with production. We've kind of come to the conclusion working through our economics that if you're going to drill the well you need to put on production. So it's really a decision about drilling wells or not and that was part of the reason that we cut $100 million out of our capital budget. The other part of this is--just to remind everyone, a lot of what we're doing still, just like it has been from day one in the Fayetteville, is learning. And we've got a lot to learn this year.

And so, when we put our budget together, it wasn't about growth rates. It was what did we need to learn to set ourselves up for the future. And that's really what we're trying to do.

Scott Hanold: Appreciate that. Thanks, guys.

Operator: And we'll go next to David Heikkinen of Tudor, Pickering, Holt.

David Heikkinen: Good morning, guys.

Harold Korell: Hi, David.

David Heikkinen: I wanted to walk through pipeline capacity and just kind of deciphering what's in your 10-Q and kind of current capacity and how the Boardwalk line steps forward over the next three years, and then also the firm commitments that you have beyond Boardwalk. Could you do that for us?

Steve Mueller: I'll run through some cost side things and then we can go as--wherever you want to go with that from there.

David Heikkinen: Yes.

Steve Mueller: Today, as we said, we've got in the high 300s going all the way across the Mississippi River into eastern markets. And that's really right on schedule with what the original Boardwalk pipeline was supposed to do. So, Boardwalk and the various companies that are involved in that pipeline have been trying to do some things to accelerate that overall production and part of this maintenance and testing and things that we're talking about was to try and get a waiver that would give you a little bit higher operating pressure, and by giving a little higher operating pressure be able to get an acceleration on the amount of gas you could get across the Mississippi River.

That's what's going on right now. They've run tests on the pipeline. There are some spots they need to repair on the pipeline and work on that, and then we'll apply for this waiver. But as far as our actual production, we're producing about what we were supposed to under the contract through the Boardwalk pipeline. Now, if we get the waiver, which would be later this year - third to fourth quarter type thing - we'll get a little acceleration. But assuming there's no acceleration in--towards the end of the first quarter of 2010, the third phase of the Boardwalk will become effective. At that time, the Boardwalk pipeline will be approximately 1.2 Bcf a day total. We'll have about 800 million a day capacity on that line.

And then, the other big pipeline that we've got firm on is what we call the Fayetteville Express. The Fayetteville Express is in its early stages, but it's still on schedule it looks like for an early 2011 timeframe for first sales. And then, there's really three steps in that contract also and in 2012 we've got about 1.2 Bcf a day on a 2.--I think 2 Bcf a day total pipeline.

David Heikkinen: Thanks.

Steve Mueller: Well, one other thing. We do have firm capacity still that goes into those Midwestern markets through Ozark and some of these other lines as well.

David Heikkinen: And that was about 400 million a day.

Steve Mueller: Yes, somewhere in that range. It varies a little bit month to month, but it's somewhere in that range. So we probably--as they're fixing and repairing some of these spots in the Boardwalk pipeline, we'll see some days there where we may be a little bit curtailed, but overall we can get our gas out. It's just the big thing is getting as much as you can across the Mississippi River and that's what all of us are trying to do.

David Heikkinen: Yes. So as you think your basis hedges and kind of where your non-hedged gas realized prices are, kind of tied to all the pipeline moves, can you think about percentage? I guess you're in the 3--400 million'ish a day that's going to high 300s that goes to eastern markets. Everything else goes Centerpoint and Ozark. How should we think about differentials as--over the kind of next couple quarters?

Steve Mueller: Well, we've said in the press release that we've purchased a basis of--on 130 Bcf of about $0.25. So we've already locked that in. Now, the real trick is as you take gas out of the mid-continent across the Mississippi River, that changes the basis on what the mid-continent gas is. So I don't know exactly how to tell you how to predict that as a lot of it just depends on how much is going which direction.

David Heikkinen: Okay. Yes, that's kind of the deciphering--I guess we know what your locked in volumes in are. We could just kind of make some assumptions of Centerpoint and Texas, Oklahoma gas prices and get a blend, so I'll try that.

Steve Mueller: Yes. That's basically what we do.

David Heikkinen: The other side of kind of improving operations and pilot tests in the Fayetteville I think continued to see well quality step up. Can you talk about the average rates and kind of how that continues to get better? And then, also thoughts around--in those pilots you want more data always, so how that's progressing? And that's it.

Steve Mueller: The--we're trying to learn several different things is what we're doing right now. We're continuing to tweak and work with our completions and the biggest thing we're doing on that side, if you remember in the fourth quarter we had done a couple of wells at 50-foot per spacing and started doing 75-foot per spacing. And the first and second quarters of this year was to test both of those. We're continuing to do that. 75 is looking really good. 50, we don't have enough information yet to tell you much about that. But so far the per spacings were reduced to--is continuing to add to that productivity.

The other thing we're doing was just learning about spacing. And we don't have enough information yet. As we've talked about in the past, we're--it's somewhere between 400 and 500 wells that we've got set to learn about that spacing. Those are all getting drilled now and it's--all of that needs about six months production before we can tell much.

David Heikkinen: I guess with two-thirds to the majority of your drilling program going towards spacing, it really isn't piloting, it's just optimizing how much down spacing you're going to have. Is that--?

Steve Mueller: --It's just trying to figure out what spacing might be in various situations, both geological across the play and in relationship to older wells that have already been drilled.

David Heikkinen: Thanks, Steve.

Operator: And we'll go next to Rehan Rashid of FBR Capital Markets.

Rehan Rashid: My questions have been answered. Thank you.

Operator: And we'll go next to Joe Allman of JP Morgan.

Joe Allman: Yes, thank you. Good morning, everybody.

Howard Korell: Good morning.

Joe Allman: Could you help us with the non-Fayetteville production? I know in the fourth quarter the non-Fayetteville production was down and it bumped up in the first quarter. Can you explain that, and then just give us some sense of the direction of that?

Steve Mueller: Well, I think the direction is kind of easy to give you a sense on. Like a lot of companies where we haven't been doing that much learning, we've cut our capital considerably. And so, we just don't have that much activity either first quarter or going into the rest of the year. So I would expect that in general you're going to see our production go down, not up, in those areas.

Joe Allman: And Steve, was the main driver for the increase in the first quarter the James Lime horizontal wells?

Steve Mueller: It--the little bit that was there was James Lime. Yes, it was all there. Really, we're only drilling--other than those couple of wells we talked about in the Haynesville, the only thing we're drilling outside Fayetteville, we have one rig working in Midway in Arkansas, and then we've got James Lime wells going down. And some of that's timing. For instance, right now, we've got seven wells that we have to complete that are James Lime wells that completions will start this week. And they got backed up a little bit because of a pipeline issue. So it's going to bounce around from quarter to quarter. But in general, you're not going to see an increase in production.

Joe Allman: Got you. And then, could you just help us with the thinking behind just dropping the rigs in the Fayetteville I guess, and how that fits into sort of--to the overall plan of development there? I mean, are you increasing efficiency so much that you just--you actually just don't need as many rigs? And as you drop down to 11 horizontals and four verticals by the end of the year, what's the thinking about into next year? And I know, obviously, commodity prices are a big factor. Can you just kind of help us with the thinking behind kind of the move here?

Steve Mueller: Yes. The--there's two things behind the move. We're trying to figure out how many wells we need to learn. And there's--that's a certain minimum number and we have to get to those numbers. And then, we're looking at the overall market out there and how much we're making cash flow-wise, wanting to be as flexible as possible as we go out into the future. And it was a combination of those two that was the drop in the overall capital budget. We think we can get enough wells drilled, and we'll get those drilled as quickly as we can and those rigs will just kind of drop off in the second part of the year. If the commodity prices come around, I would fully expect you'll see us reevaluate. If they go down, we'll reevaluate, and if they go up, we'll reevaluate.

Certainly, we've got a lot of wells to drill. So long-term, 11 rigs or even 15 rigs aren't the right answer.

Harold Korell: Yes. I think to add to that, the discussions that we've had in the past have been that we want to stay true to our concepts about present value created per dollar invested. And when we look at prices now and use the forward curve, the economics of what we're drilling in the Fayetteville Shale are still fine in terms of the present value created per dollar invested. But if one just looks at today's price and keeps it flat, then those are in a little bit of a pinch. So the other thing that we've talked about in the past is we want to keep an eye on our debt levels and we want to maintain flexibility and not incur an inordinate amount of debt.

So the current move is--I'd say it's a compromise position of what price should you really use to do the economics. Well, I don't think you should use today's price flat, but still it has a bearing on how we feel about it. It also has a bearing on our borrowing. So the step back of about $100 million continues to give us more options in the future as to which--the things that we can do and pursue by not drilling the wells today, by cutting $100 million of capital out. And it's just $100 million we still have in the war chest available in our borrowing capacity. So it's a--I'd say it's a conservative approach to it, and at a time when our production volumes are growing tremendously anyway.

Joe Allman: Okay, that's very helpful. Thank you very much.

Operator: Your next question is from Tom Gardner of Simmons & Company.

Tom Gardner: Question about your hedging strategy going forward, specifically looking towards 2010. Can you talk about perhaps what gas price would you consider too low to lock in, as you look to hedge out 2010?

Steve Mueller: Well, current prices are obviously too low for us to lock in. For us, we’ve got a really good hedge position for what we’ve got hedged right now for the remainder of the year; near the $8s and if you look at long-term data, it looks like historically somewhere between $6 and $8 is what the industry needs to break-even. With shale plays, maybe that’s a lower number than it has been, obviously with conventional drilling. So, what is that long-term trend going to be? Is that $6 to $8, is it going to be $6 to $7? But we think marginally prices have got to get above $6 before we start really looking at the screen very hard, and we think that we’re going to have opportunities to hedge when we do see that intersection of supply curve start hitting closer to the demand curve. So we’ll be watching it very closely, but there’s nothing in the near-term that we expect to be doing.

Tom Gardner: I got you; that’s helpful. A more specific question related to drilling costs, specifically cost savings from pad drilling. You’re estimating I guess the average well cost to go down to $2.9. Can you give us an idea of what your pad drilling savings is, and what the percentage of second well on a pad drilling might look like from 2009 going into 2010?

Steve Mueller: As you know, we’re building pads everywhere, and in 2009, as well as 2010, we’ll be drilling about 200 wells that are just single wells holding sections and in some cases that may be two wells off a pad. You don’t get a lot of cost savings there. You get a little bit of rig time, skidding 10 feet versus moving a mile or something to a pad, which is about a day’s worth of rig time. The real cost savings comes when we do development and get into full blown development phase. I don’t know exactly when that is. It’s not 2009, and it’s probably not in 2010 for much of it. When we get to that point, we should start seeing some significant savings.

And to give you kind of a feel for that, one of the recent projects we did trying to do some downspacing, we drilled four wells off a single pad. It took us 28 days total to drill those four wells, so that’s 7.25 days a well. And so we know that the 12 we’re doing right now is not the right number when we do get to the development phase. In addition to that, when you’re fracing on the location where you have several wells, we do use the same kind of techniques they use in the Barnett where you do the zippers and you move back and forth between. There’s quite a bit of savings in both time and amount of effort, plus hopefully even better fracs when you get done with that. Again, except for just a little bit of the downspacing work when you’ve got wells close together, we’ve got two or three on a pad, you haven’t seen any of that savings yet.

Operator: Your next question is from Gil Yang of Citi.

Gil Yang: Could you clarify the amortization benefit of $0.30 to $0.40, was that paid in the first quarter or was that only second quarter and going forward?

Greg Kerley: That will be seen going forward. The impairment charges made at the end of the period and the amortization rate of $1.82 is what we average for the first quarter. Going forward, we would expect that to be $1.40 to $1.50 an Mcf equivalent, with all other things being equal.

Gil Yang: Great. Question I have is; can you talk a little bit about the Haynesville in terms of the well in Shelby that IP’d at 7.2 million a day, is that a 24-hour test, is it a 30-day test, and it’s currently producing at 3 million, is it being curtailed in any way and how many fracs were there and how closely spaced were they?

Steve Mueller: Just to remind you, it’s 2,700-foot lateral, I think it was six stages of fracs in it, which from a stage per foot of laterals is about equivalent to what you’d see in other Haynesville wells or just the laterals are considerably shorter than the ones you normally see rates on. That test was the test that we gave to the state after we put the well on production. It was not an IP or some kind of test rate that was immediately after the well first was tested, so there was a little bit of timeframe on that. The state testing is 24-hour testing.

As far as are we choking it back or anything from that standpoint, 13/64 choke is what’s it’s been flowing at for a considerable period of time. So, I don’t know if you want to call it choked back or not, but that’s what we’ve been flowing it at. The well’s holding up strong. You’re seeing very little pressure drop at 13/64, so that’s kind of what the well is.

Operator: Your next question is from Brian Singer of Goldman Sachs.

Brian Singer: I wanted to follow-up on Scott, David and Joe’s questions with regards to CapEx versus learning versus growth. When you considered whether to drill even less and say keep production guidance flat versus increasing, can you speak to the gas price break-even and discount rates in your present value calculations and also how much flexibility exists for further budget reductions until you may begin to give up acreage in the Fayetteville or other areas?

Steve Mueller: I can start with the giving up acreage part of that. The rigs we have left in our conventional areas, basically are there holding acreage. There isn’t much other than that going on in that direction. In the Fayetteville, as I said, of that 600 wells, roughly 200 of those will hold acreage this year, and we need to drill at that pace for the next couple of years to hold all the acreage, but we shouldn’t have any issues doing that.

From the standpoint of having less production and economics, going back to Harold’s comment about our PVI goals, for our PVI goals you need to have a flat price somewhere in the mid-$4s to hit our PVI goal. And that’s why he said before, if you start just a flat price going out, you’re challenged right now in economics if you have some kind of escalator in the future, we still ought to have decent economics in what we’re doing. So, that’s part of the debate that’s been going on internally; how much do you slowdown when you slowdown and how do you keep that flexibility?

Harold Korell: And Steve, I think those mid-$4s are with today’s well cost, they’re not with the development scenario maybe that would occur as we’re drilling multiple wells on pads and so on down the road.

Steve Mueller: I think that answered everything you had there.

Brian Singer: Yes, I think so. Anyway, I could follow-up a little on the discount rate question. But secondly, it seemed like operating expenses that were not related to internal transfer costs, have fallen significantly on a per unit basis in the last couple of quarters, and I’m wondering if there’s any color -- first of all if that’s the right interpretation and if there’s any color on what’s driving that?

Steve Mueller: We are very sensitive on our LOE costs to the gas price, because about half of that total LOE is compression and almost all of that is the gas price. So, as you’ve seen that gas price go down over the last couple of quarters, you’re seeing our LOE go down. The actual what I’d call fixed LOE has actually gone up a little bit; it’s almost flat, but it’s gone up a little bit and so really you’re just seeing the gas price move up and down is what’s happening.

Operator: Your next question is from David Snow of Energy Equities Incorporated.

David Snow: I was hoping everybody would have dropped off before I asked this, but do you have to do your ceiling test on a quarterly basis or is it optional as to whether to do it annual or quarter?

Greg Kerley: No, you have to do it at the end of each quarter. Now there’s certain rules that would change -- that are scheduled to change at the end of the year about what pricing you use that lets you use more of an average price and if we were in that time period with those rules, it looks like we probably would have been fine, but right now as we go through this year on a quarterly basis, the rules are it’ll be what price is in effect at the end of each period, in the second and third quarter also. End of the year will be different rules.

David Snow: Does that enter into any of your covenants indirectly or is it not an issue?

Greg Kerley: No, it is not an issue at all with our covenants. We have those kind of non-cash -- any non-cash adjustments to our earnings or equity are excluded. But again, even if it was included, we’re 25% debt to capital and we do have financial covenant that our debt can’t exceed 60%, so we have significant room in our covenants. But it is not considered one of the effects of it.

David Snow: Okay. And I was wondering if you could translate your formula for PV needs to just what the straight ROI is at $4.50 flat?

Steve Mueller: On an internal rate of return type thing, compounded rate of return, roughly in the 20% range. It depends on the shape of the wells in the way it works, but it’s roughly that number.

David Snow: On changing your spacing perfs to 75 feet, what type of improvement do you get versus what you’ve been doing?

Steve Mueller: I think if you just look at that chart and look at the IP changes as you went from -- I’d take the average of the first and fourth quarter and then look at that compared to the third quarter, that’s really when we put the 75-foot in effect, so that’s really where you’re going to - -- that’s probably the best way to answer that one.

David Snow: How much more does it cost?

Harold Korell: I think we’re trying to limit this to two questions per person, if we could.

Operator: Your next question is from Robert Christensen of Buckingham Research.

Robert Christensen: Question for you; what’s your next decision point on the Haynesville wildcat? I guess you’ve drilled two wells, but what comes up next in the joint venture and who makes that decision, you or your private party?

Steve Mueller: We are carried completely for the first two wells through the pipeline. The second well will be completed here in the next 45 to 60 days, and you’ll obviously the next big thing is get that completed and see what it looks like compared to your first well. And then the other big thing is that there are some wells drilled around us by other companies and get a little information on what they’ve got and then you can decide how good it is and what other drilling you want to do.

Robert Christensen: Is there takeaway capacity in the area?

Steve Mueller: Yes.

Robert Christensen: And a final, off subject, the Marcellus, you just leased land there, I guess in the quarter. What were you paying on average and other terms related to those 23,900 acres, please?

Steve Mueller: I think we said in the last conference call that we paid a little over $8 million for about 21,000 acres and we did some cleanup work out there to get that last couple thousand acres.

Operator: Your next question is from Mike Scialla of Thomas Weisel Partners.

Mike Scialla: Just a couple of follow-ups to Bob’s questions on the Haynesville. Based on what you’ve seen on that first well and maybe some of the results that you’ve seen from other operators, how far away do you think you are from making that economic right now, and what did that first well cost you?

Steve Mueller: The first well had a lot of science on it, so it’s not really representative on its overall cost. We think we need to have something less than $10 million, between $8 and $10 million total cost on the well and we need a little more encouragement probably on the production rate than what we’ve seen to date to just pound the table and say oh this is a great play, but it’s very intriguing.

Mike Scialla: So maybe with a longer lateral and some cost savings you’ll see later--?

Steve Mueller: Once you start a little longer lateral and take out the fact that we drilled the vertical and cored both of these wells and get them to really where you’re just drilling the wells for the production, it starts sounding interesting at that point.

Mike Scialla: And then same on the Marcellus, what’s encouraged you to add the acreage that you have?

Steve Mueller: Well, there’s just been a lot of wells. You know, in 2008 there were almost 300 wells drilled in the Marcellus. There were several in and around our acreage besides the ones we drilled, and we really like what we’re seeing from a lot of different perspectives there.

Technically, probably the thing that we like best is there’s more free gas in the Marcellus versus absorbed gas than a lot of the shales out there, and you’re seeing some pretty good initial rates because of that.

Mike Scialla: Thank you.

Operator: We’ll go next to Ray Deacon of Pritchard Capital.

Ray Deacon: Yes, hey, good morning. I was wondering if you could comment on the $1.8 billion budget, if you do get more reason for optimism and increase spending on the Bossier/ Haynesville, would you take rigs away or would you add to the 1.8 billion of CapEx?

Harold Korell: I think we’re just going to have to wait and see. I don’t think we are prepared to answer that question right now.

Ray Deacon: Okay, got you. And I guess kind of a little bit tied to that, is there -- you’re going to be adding a lot of PDPs between now and November and there’s a lot of concern about what the banks may do to credit lines. So, I guess, do you feel like you can be slightly more constrained at the end of this year in terms of availability to you on your borrowing base, six, seven months from now, or do you think the PDPs will offset that?

Greg Kerley: Well, Ray, this is Greg Kerley. You might not recall our credit facility is somewhat of an anomaly compared to a lot of our peers. We do not have a borrowing base facility.

Ray Deacon: Okay. It’s (inaudible) the balance sheet.

Greg Kerley: It is an unsecured line and so it wouldn’t have any impact, an SID impact with the swings in prices.

Ray Deacon: Okay. Thanks very much.

Operator: And we’ll go next to Brian Kuzma of Weiss Multi-Strategy.

Brian Kuzma: Good morning, guys. When you look at your April IP rates around like 3.7 million a day, I mean, does that mean you guys are seeing like 6 and 7 million a day IP rates on your goodwills?

Steve Mueller: We haven’t seen any.

Brian Kuzma: Okay.

Steve Mueller: There has been a 6 reported by another company out there, but we haven’t seen 6 and 7.

Brian Kuzma: Okay. And then just to clarify on the hedging and the takeaway, when you talk about having these quantities -- basis hedged in the second half of the year, that’s in addition to the 365 you’ve got to Lula, Mississippi.

Steve Mueller: No, what we have -- we’ve got gas hedged at a certain price and that total for the year was about 130 Bcf. It was like 134 Bcf. And then basis hedging is just the difference between NYMEX and whatever you have at a certain delivery point and that’s a different kind of hedge. You’re just hedging that little bit of basis. It happens that for the next three quarters, we have roughly 130 Bcf of basis hedge, but those are two different kinds of hedges.

Brian Kuzma: I got it. So you guys are -- but then when you combine your FT with your basis hedges, I shouldn’t look at that as you guys being 90% hedged out of the Fayetteville then?

Steve Mueller: No.

Brian Kuzma: No, that’s not right?

Steve Mueller: No, but the -- you have to hedge basis to certain points. There are certain aggregating points in the country, and for instance, some of our gas that’s going into the Ozark pipeline, for instance, has an aggregation point that’s in the Central part of the U.S., other parts Southeast or you could be true NYMEX and that’s in Louisiana. And so your basis is just the difference between NYMEX and whatever that aggregation point is. It’s not a physical hedge like our other hedges are on price.

Operator: And we’ll go next to Jack Aydin of Keybanc Capital Markets.

Jack Aydin: Hi, guys. Most of my questions were answered, but I have one. Looking at your acreage and the 105,000 acres in the Angelina Trend, did you test the Haynesville formation in this acreage this year at all, or last year?

Steve Mueller: Well, the test we talked about that Haynesville well is in kind of the middle of that acreage position. That’s where that’s at.

Jack Aydin: Okay. Thank you.

Operator: And we’ll go next to Marshall Carver of Capital One Southcoast.

Marshall Carver: Yes, a couple of quick questions. When you talk about needing wells to cost, 8 to 10 million in the East Texas, Haynesville/Bossier, was that -- were you indicating that the first well was more than 10 million, but you think you can the 8 to 10 longer term or how should we think about longer term cost there?

Steve Mueller: Well, I think you can certainly make an AFE that would show that we could drill a well for $8.5 million. I can tell you that the first two wells we drilled, as I said, we took whole cores, we ran a bunch of different logs that you normally wouldn’t run, and when you’re taking those whole cores, you actually drill a vertical well first and then backed up and did the horizontal part of the well. So, yes, it was considerably higher than the 8 to $10 million range.

Marshall Carver: Okay. That’s helpful. And the April wells that you drilled so far in the Fayetteville, are those reflective of what you think the Q2 wells will be like for IP rates or is there anything special about April that you probably won’t get in May?

Steve Mueller: Yes, I don’t -- I have no idea. There’s nothing different about where we drilled wells really for the last two and half quarters. We’re going across the entire play, we’re drilling a lot of different areas that we’re targeting and there’s nothing different about the third quarter or second quarter, first quarter, in that respect. Now, statistically, all kinds of weird things happen and as you’re learning, that just goes with it, so I can’t even kind of guess what’s going to happen.

Marshall Carver: Okay. That’s helpful. Thank you, good quarter.

Steve Mueller: Thanks.

Operator: And we’ll go next to Jeff Hayden of Rodman & Renshaw.

Jeff Hayden: Hey, guys. Just a quick question follow-up to Brian Singer’s question from earlier. When you were talking about the wells, the well count that you need to hold your acreage, was that the 200 wells you referred to that you have to keep doing to kind of be able to hold all your acreage?

Steve Mueller: Yes.

Jeff Hayden: Okay. And then assuming you just kind of stay at the 11 horizontal rigs, about how many gross wells do you think you’d drill next year?

Steve Mueller: Well, we’re averaging about 11 days a well. I’d have to -- it’s 540, 500-and-something, whatever that number is.

Jeff Hayden: Okay. And that’s -- and then out of that, about how many are the kind of outside operated wells versus how many of those are the ones you guys would operate?

Steve Mueller: Well, this year, roughly 100 of the 600 wells are outside operated.

Jeff Hayden: Okay. I appreciate it, guys.

Operator: And we’ll go next to Omar Jamma of Owl Creek.

Omar Jamma: Good morning. I had a question on your type curve chart. You’ve seen a notable improvement over the last few quarters and years. And two questions, really, one, just eye-balling the chart, it appears that the declines have become steeper, and so I’m just wondering if you’re not just pulling forward production, as opposed to increasing the overall EUR from some of these wells. So that’s the first question.

Steve Mueller: I think you need to be a little careful calling them type curves, at least from the production data and we put some type curves on there, but you’ve got to remember that what’s happening here is you’re rolling through those increases in IP, 30 and 60 day rates. So as you follow this over time, those curves have kind of pulled themselves up over time, and so we just have to watch as we go out in the future, but I don’t know that there’s anything there that we see that says we’re accelerating versus some other (inaudible).

Omar Jamma: Okay. And then the other question I had, it seemed like a couple of years ago, you were doing a lot more drilling and just kind of seeing what you had, as opposed to now, where you seem to be getting a little more aggressive in the development. I know you still have a huge amount of running room, but I’m curious if you could just talk us -- you say you’re drilling across the play, but it seems like you might be -- actually might have found a better area within the play that you're more focused on recently. So I’m just curious if you could share your thoughts on what we can infer from some of the data you’re presenting here about the potential longer term for the kind of results that you’ll see across the whole play, as opposed to perhaps the sweet spots that you’re drilling now.

Steve Mueller: I’m not sure if you saw a map where we’re drilling. I don’t know that -- you say that we’re drilling these sweet spots. We literally -- on 800,000 acres, the only place we haven’t been drilling, and we will be drilling later this year, is a little over 100,000 acres in the far northwest corner that’s federal, and we’ve got this federal unit almost together and then we’ll drill in it this year. But other than that, we drilled across the entire play.

Probably the other way to kind of answer your question, of the roughly just under 1,000 wells that we’ve drilled and completed, about 290 of those wells were 3 million a day or better, and if you looked at a map where that’s at, they’re across that entire acreage block. There isn’t just an obvious sweet spot where they’re all sitting there and then it drops off from that. So I don’t know that we found the best spot or the worst spot. Certainly, there’s geologic differences as you go through. There’s faulting and all kinds of things, thicknesses and that, but our intent has not been to drill just one little sweet spot.

Omar Jamma: But do you think the data you’re presenting is an accurate sampling or is it a large enough sample to have a feel, or do you think it’s still too early to be able to infer what the longer term EURs will be from the data we have?

Steve Mueller: I think if you look at whether it’s the table where we’ve got the number of completions per quarter, we’re consistently doing between 70 and 100 completions per quarter. Certainly, if you start talking about 70, you might talk about statistics being off a little bit, but if you’re over 100, you’re starting to get enough for statistics there. When you look at the actual production graph, we do have the data there on how many wells and obviously, the early part of that’s got a lot more wells than do the later parts. So, the far end of that has less statistical value than the front end does, but we’re learning. From day one, we’ve been learning; we’re still learning a lot. Development is still a ways out, as we try to learn some of these major things.

Omar Jamma: Okay. That’s helpful. Thank you very much.

Operator: (OPERATOR INSTRUCTIONS). We’ll take a follow-up from Scott Hanold of RBC Capital Markets.

Scott Hanold: Hey, one real quick follow-up, and you gave some of the info away, but of the 600 wells you have planned for 2009 in the Fayetteville, I think you indicated 100 of those were not operated wells. What was that number at when you were originally targeting 650 wells, and do you expect there could be some risk as other operators pull back cap ex a little bit?

Steve Mueller: We’ve actually -- in our revised capital budgets, we’ve actually added about $10 million to the outside operated. We’ve seen more AFPs than we originally planned, and that’s not that many more wells, but we’re not seeing any slack there.

Scott Hanold: Okay. So how great a --

Steve Mueller: Let me put it this way. We’re seeing it two different ways. The number of AFEs have actually increased a little bit here recently. The other thing that’s happened is that our working interest in those AFEs has gone up since our original budget and what we assumed in the original budget also.

Scott Hanold: Okay. And how correlated are AFEs to, I guess, those outside operators’ ability to actually go out and drill those wells?

Steve Mueller: Oh, that’s a fair correlation.

Scott Hanold: Okay. Thank you.

Steve Mueller: Some of those wells don’t get drilled, but usually, they drill them.

Scott Hanold: Thank you.

Operator: And I’ll take a follow-up question from Rahan Rashid of FDR Capital Markets.

Rahan Rashid: Not to beat a dead horse here, but the improving IPs then sequentially is simplistically the more tighter fracing? Is that the driver?

Harold Korell: A combination of longer laterals, the perforation clusters and the frac jobs we’re doing, yes.

Rahan Rashid: Okay. Okay. The $2.9 million per well, does that reflect most of the service cost deflation that we have seen, or should we expect, all else being equal, that cost to come down because of cost reductions?

Steve Mueller: That has our estimate for what reductions will be -- yes.

Rahan Rashid: And last one on free gas and absorbed gas, have you kind of -- have you begun to notice when those absorbed gas kick in and how could that help the longer term decline rates?

Steve Mueller: We really have not -- and I assume you’re talking about the Fayetteville shale.

Rahan Rashid: Yes.

Steve Mueller: We have not got a good feel for that yet. That’s one of the things we’ve been trying to monitor, but we don’t have a good answer yet.

Rahan Rashid: Okay. Thank you.

Operator: And we’ll go next to David Snow of Energy Equities, Inc.

David Snow: I was just trying to pull up a map of your drilling, and I was astounded when you said that it’s been pretty constant over the whole play. I was thinking that just the thickness alone and the depth varies considerably. Am I right that you’ve gotten away from the well and the various sections of identifying the play and it’s all pretty much giving you comparable results?

Steve Mueller: I won’t say that it’s giving us completely comparable results. You still have, in the shallow section, lower pressures and in general, you're going to have little shorter laterals than you are in the middle or deeper parts of the play. And there are certain parts of it that have more or less faulting as you go through it, but consistently across the play, we’ve seen 3-plus-million a day wells.

David Snow: Terrific, okay. And these 75-foot intervals, are they costing you a lot more per well, or just about a little bit more?

Steve Mueller: Kind of the way to think about it, a year ago, 60% of the well cost was drilling, 40% of the well cost was completion. Today, it’s almost flip-flopped. It’s about 40% of it’s drilling because we’re taking the days out of the drilling curve, but because we’re putting more energy in the ground, about 60% is completions.

David Snow: So the $2.9, how many -- is it like another $50 million to go to 75-foot intervals?

Steve Mueller: Well, that $2.9 has reflected both 50 -- the percent that we think will be 50-foot spacing and 75-foot spacing and the other kind of spacing on first, so that’s kind of a combination of everything.

David Snow: Thank you very much.

Operator: And at this time, we have no further questions. I would like to turn the conference back over to Mr. Harold Korell for any additional comments.

Harold Korell: Well, thank you and thank all of you for joining us today. I wanted to end with just sort of the big picture. For those of you who have had an opportunity to see our Annual Report, there is one bird that seems to be leaving the flock in a positive direction, and we’ve done that, as we’ve said before, through a real tight focus on value creation and idea generation. And we’re continuing that today. We are walking through a period of some stress in our industry very clearly, but where I see this going is out the other end of this, there is a blue sky ahead.

Thanks for joining us and have a good day.

Operator: And that concludes today’s Southwestern Energy Company conference. Thank you for your participation.

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2009 and March 31, 2008.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

	3 Months Ended March 31,
	2009	2008
	(in thousands)
Net income (loss) attributable to Southwestern Energy:
Net income (loss) attributable to Southwestern Energy	$    (432,830)	$     109,029
Add back:
Impairment of natural gas and oil properties (net of taxes)	558,305	--
Net income attributable to Southwestern Energy,   excluding impairment of natural gas and oil properties	$     125,475	$     109,029

	3 Months Ended March 31,
	2009	2008
Diluted earnings per share:
Net income (loss) per share attributable to   Southwestern Energy shareholders	$         (1.26)	$           0.31
Add back:
Impairment of natural gas and oil properties (net of taxes)	1.62	--
Net income per share attributable to Southwestern Energy shareholders,   excluding impairment of natural gas and oil properties	$          0.36	$           0.31

	3 Months Ended March 31,
	2009	2008
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$     407,295	$     297,087
Add back (deduct):
Change in operating assets and liabilities	(34,740)	(13,370)
Net cash provided by operating activities before changes   in operating assets and liabilities	$     372,555	$     283,717

	3 Months Ended March 31,
	2009	2008
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$    (727,893)	$     165,710
Add back:
Impairment of natural gas and oil properties	907,812	--
E&P segment operating income excluding impairment   of natural gas and oil properties	$     179,919	$     165,710