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): February 27, 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 February 27, 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 February 27, 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: February 27, 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 February 27, 2009 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Company

Q4 2008 Earnings Conference Call

Friday, February 27, 2009

Officers

 Harold Korell; Southwestern Energy; Chairman and CEO

 Steve Mueller; Southwestern Energy; President

 Greg Kerley; Southwestern Energy; CFO

Analysts

 Tom Gardner; Simmons & Co.; Analyst

 Jeff Hayden; Rodman & Renshaw; Analyst

 David Heikkinen; Tudor, Pickering & Holt; Analyst

 Joe Allman; JPMorgan; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Scott Hanold; RBC Capital Markets; Analyst

 Gil Yang; Citi; Analyst

 Mike Scialla; Thomas Weisel Partners; Analyst

 Marshall Carver; Capital One; Analyst

 Robert Christensen; Buckingham Research Group; Analyst

Presentation

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

Harold Korell:  Well, it's actually only CEO and Chairman.  Mr. Mueller, our President, is here with us, and that all is going to change down the road in a few months.

But good morning, and thank you for joining us, and Steve is here with me, and Greg Kerley is also here.  

If you've not received a copy of yesterday's press release regarding our fourth quarter and year-end 2008 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 sections of our annual and quarterly filings with the SEC.  

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

Well, 2008 was a tremendous year for Southwestern Energy.  We recorded exceptional production and reserve growth as we continued to move up the learning curve in the Fayetteville Shale.  We also reported record results in earnings and cash flow, and the proactive management of our balance sheet has placed us in great financial condition, with a debt-to-total capitalization ratio of 23% and nearly $200 million of cash on hand at year-end and nothing borrowed on our $1 billion unsecured credit facility.

However, the key accomplishment for us in 2008 was clearly the progress we made in our Fayetteville Shale play.  Steve will give more details on all of our operating areas in a moment, but overall, I could not be any more pleased with our accomplishments in 2008.  

As we enter 2009, we will continue to focus on organic growth and the value added for each dollar we invest.  As a result of the low commodity price environment, we currently have a planned capital program of $1.9 billion for 2009 compared to the $2 billion plan that we announced in December.  

Our current plan includes releasing four rigs during 2009.  We will actively manage our capital program and have the flexibility to make further reductions if we find ourselves in this low natural gas price environment for an extended period of time.

So while there is a lot of uncertainty in today's markets, we feel confident that when our industry comes out the other side of this commodity price cycle, that Southwestern Energy will be extremely well-positioned, financially healthy, and growing significantly at low cost levels.

On a more personal note, yesterday we announced my planned retirement and the planned promotion of Steve Mueller to CEO.  We are extremely fortunate to have Steve and our strong management team to guide Southwestern Energy into the future.

Being here at Southwestern Energy has been a fabulous experience for me over the past 12 years, and I've been so fortunate to be a part of this value creation story.  

I'd like to 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.  

I want to personally thank you for your mentorship to me for so many years and for your leadership here at Southwestern Energy the past 12 years.  As anyone who's met you knows, you are the right person and doing the right thing, and all of us at Southwestern look forward to your continued leadership in the future.  

Now, let me get back on script and talk about 2008.

In 2008, our gas and oil production totaled almost 195 Bcfe, up 71% from 2007, primarily as a result of increased production from our Fayetteville Shale play, where our production was 135 Bcf in 2008.  This is more than double the 53.5 Bcf we produced from the Shale in 2007.  

We produced 31.6 Bcfe from East Texas and 24.4 Bcf from our Traditional Arkoma Basin area in 2008.  Production from both of these areas was also higher than in 2007, up from 29.9 Bcf in East Texas and 23.8 Bcf in the Arkoma Basin.  

We've produced an additional 4.1 Bcf in 2008 from our other areas combined, including from our Gulf Coast and Permian Basin properties that we sold during the year.  

In 2008, we increased our year-end proved reserves by 51% to 2.2 Tcfe.  The 2.2 Tcf of proved reserves were located approximately 71% in the Fayetteville Shale, 16% in East Texas, and 13% in the Conventional Arkoma Basin.

In 2008, we added 920 Bcf of proved reserves and had net upward revisions of 98 Bcfe.  Both the additions and the revisions were primarily driven by the performance of wells in our Fayetteville play.  

During 2008, we sold all of our remaining assets in the Gulf Coast and Permian Basin areas and approximately 55,600 acres in our Fayetteville Shale play.  In aggregate, these divestitures had proved reserves of approximately 90 Bcf.  

Including both our additions and revisions, we replaced 523% of our 2008 production at an F&D cost of $1.53 per Mcfe⁽¹⁾.  Excluding revisions, we replaced 473% of our 2008 production at a finding and development cost that was $1.70 per Mcfe⁽¹⁾.  Proved developed reserves accounted for approximately 62% of our total reserves at year-end 2008.

In 2008, we invested a total of $1.6 billion in our E&P business and participated in drilling 750 wells; 479 of those were successful, 11 were dry, and 260 were in progress at year-end.  Of the $1.6 billion invested, approximately 81%, or $1.3 billion, was in exploratory and development drilling and workovers, $83 million for leasehold acquisition, $66 for seismic expenditures, and $118 in capitalized interest and expenses and other technology-related expenditures.

Moving on to the Fayetteville play, gross production from our operated wells in the Fayetteville Shale play increased from approximately 325 million cubic feet per day at the beginning of 2008 to approximately 720 million cubic feet per day at year-end to its current level of approximately 750 million cubic feet per day.  

We estimate that our 2009 production from the Fayetteville Shale will range between 229 and 232 Bcf, up approximately 70% from 2008.  We invested approximately $1.2 billion in our Fayetteville Shale drilling program during 2008, added 984 Bcf in new reserves at an F&D cost of $1.21 per Mcf⁽¹⁾.  This includes upward revisions of approximately 159 Bcf due primarily to the improved well performance.  The finding and development cost excluding those revisions was $1.44 per Mcf⁽¹⁾.  

Total proved net gas reserves booked in the Fayetteville Shale at year-end 2008 was 1.5 Tcf, compared to the 716 Bcf of reserves booked at the end of 2007.  The average gross proved reserves for each of the proved undeveloped wells is approximately 1.9 Bcf, up from 1.5 Bcf per well at the end of 2007.  Our gross proved reserves for wells that were placed on production in the second half of 2008 averaged 2.2 Bcf per well.  

During 2008, we continued to improve our drilling practices in the Fayetteville Shale.  Our horizontal wells had a completed average well cost of $3 million per well, average horizontal length of just over 3,600 feet, and average time to drill to total -- to drill to total depth of 14 days from reentry to reentry.  This compares to an average completed well cost of $2.9 million per well, average horizontal lateral length of 2,650 feet, and average time to drill to total depth of 17 days during 2007.

Our initial producing rates also continued to improve, as wells placed on production during 2008 averaged initial production rates of nearly 2.8 million cubic feet per day compared to an average initial rate of approximately 1.7 million cubic feet per day in 2007.

During the fourth quarter of 2008, our horizontal wells had an average completed cost of $3.1 million per well, average horizontal lateral length of 3,850 feet, and average time to drill to total depth to drill wells of 13 days.  This compares to an average completed well cost of $3 million per well, average horizontal lateral length of 3,736 feet, and average time to drill to total depth of 12 days in the third quarter of 2008.  

We currently are running 22 rigs in Fayetteville Shale play, 15 that are capable of drilling horizontal wells and 7 smaller rigs that are used to drill a vertical section of the holes.  Expected lateral lengths should average approximately 4,000 feet in 2009, and completed well costs are expected to decline slightly in 2009 to approximately $2.9 million per well.  This lower cost is a result of lower oil field service costs that are projected to more than offset higher costs associated with the evolving completion techniques and longer laterals.

Since 2007, the continuous improvement of the Company's completion practices have consistently resulted in quarter-over-quarter improvements in average initial production rates of operated wells placed on production.  The approximately 16% increase in the average initial production rates for the fourth quarter of 2008 also reflect the impact of delay in the Boardwalk Pipeline.  

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

In addition, the Company generally placed wells with the highest rates -- initial rates on production first during the quarter.  As a result, the remaining backlog of shut-in wells that were placed on production in the first quarter of 2009 were generally at lower rates.  

These lower rates are expected to result in a lower average initial production rate for the first quarter of 2009 as compared to the fourth quarter of 2008.  

Results through the first six weeks of 2009 indicate that the Company's operated wells have an average initial production rate of approximately 2.9 million cubic foot per day.  

At year-end, we held approximately 875,000 net acres in the play, down from approximately 906,700 acres at year-end 2007 due to the sale of acreage in May 2008 to XTO Energy.  

Approximately 26% of our leasehold acreage is held by production, excluding 125,000 acres in this traditional fairway portion of the Arkoma Basin, and 35 to 40% of the total 2009 wells are planned to hold acreage.  

We have approximately 961 square miles of 3-D seismic data in the play and plan to acquire approximately 139 square miles more in 2009.  This will bring our total seismic coverage to approximately 41% of our net position in the Fayetteville Shale, excluding our Fairway acreage.

In the Conventional Arkoma, we have approximately 281 Bcf of reserves compared to -- in 2008 compared to 304 Bcf at year-end 2007.  

In 2008, we invested approximately $135 million here and participated in 81 wells -- 67 were successful and 8 were in progress at the year-end.  It resulted in a 92% success rate.  Net production from the Conventional Arkoma properties was 24.4 Bcf in 2008, compared to 23.8 Bcf in 2007.  

In 2009, we plan to invest approximately $60 million in the Conventional Arkoma program and drill approximately 25 wells.  

We have approximately 351 Bcf of reserves in East Texas compared to 353 Bcf at year-end 2007.  

In 2008, we invested approximately $160 million and participated in 50 wells in East Texas, of which 42 were successful and 8 were in progress at year-end, resulting in 100% success rate.  Net production from East Texas was 31.6 Bcfe in 2008, compared to 29.9 Bcfe in 2007.  

Our 2008 drilling program was primarily focused on drilling the James Lime formation in our Angelina River trend area.  

During 2008, we participated in a total of 32 wells targeting James Lime horizontals.  The average gross initial rate for the 15 operated wells we placed on production in 2008 was 9.1 million cubic foot per day.  At year-end 2008, we had just over 100,000 total gross acres, approximately 86,000 were undeveloped, and approximately 17,000 gross acres developed in the Angelina trend.

In the second quarter of 2008, we signed a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale interval in Shelby, Nacogdoches, and St. Augustine County, Texas.  

The first horizontal well, the Red River 877 #1, located in Shelby County, reached total measured depth of 16,144 feet in the fourth quarter of 2008 with a 2,718 foot lateral length.  It was completed in the first quarter of 2009 and is currently being tested.  

We plan to start drilling the horizontal lateral of the second well, the Red River 164 #1 within the week.  It is expected to be completed and tested in the second quarter of 2009.  We are encouraged by our results to date and may invest more capital in 2009 than currently planned in the Haynesville/Bossierville (sic) Shale play.  

In 2009, the current plan is to invest up to $110 million in East Texas, to participate in approximately 40 wells, 34 of which are planned to be horizontal wells targeting the James Lime formation.

At year-end 2008, we had approximately 138,600 net undeveloped acres in the United States outside of our core operating areas.  We invested approximately $73 million in new ventures and programs in 2008, including $58 million in the Marcellus shale play in Pennsylvania.  At year-end 2008, we had approximately 115,000 net acres in Pennsylvania, under which we believe the Marcellus shale is prospective, at a total cost of about $530 per acre.

During 2008, we drilled our first four wells, including our first horizontal well on the acreage in Bradford and Susquehanna Counties, three of which have been production tested.  In the first quarter of 2009, we increased our acreage position in the Marcellus with the purchase of approximately 22,000 net acres in Lycoming County, Pennsylvania for approximately $8.2 million.  As a result, we currently have approximately 137,000 net undeveloped acres in Pennsylvania.  We plan to invest approximately $80 million in various new venture projects in 2009, including the Marcellus shale play.  

In summary, as Harold mentioned, we are very pleased with the results in 2008.  Our planned capital investment plan for 2009 of approximately $1.9 billion continues to build on that success.  It includes approximately 86%, or $1.6 billion, for E&P, and $220 million for midstream services.  Managing through any significant drop in product price is always challenging, but with our focused approach and our concentration on adding value we're looking forward to continued strong results in 2009.  We expect to meet or exceed our PVI target, have approximately 45% production growth, and significant increases in proved reserves.

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, our production growth drove significant increases during 2008 in both our earnings and cash flow, and we ended the year with one of the strongest balance sheets in our history.  For the calendar year, we reported net income of $568 million, or $1.64 a share, more than double our prior year record results and our cash flow from operating activities before changes in operating assets and liabilities increased over $500 million to almost $1.2 billion for the year⁽²⁾.

For the fourth quarter, we reported earnings of $104 million, or $0.30 a share, a 46% increase over the prior year as the significant growth in our production volumes substantially outweighed a 14% decline in our average realized gas price and higher operating costs and expenses.  

Our commodity hedge position increased our average realized gas price by $0.79 in the fourth quarter, which helped us offset some of the effects of lower spot market prices and widening locational market differentials or basis that occurred during the quarter primarily as a result of the delay in the construction of the Fayetteville lateral portion of the Boardwalk pipeline.  Phase I of the Fayetteville lateral was placed in service on December 24 and we are currently moving a little over 400 million cubic feet of gas per day through the pipeline.  

We currently have close to 48% of our 2009 projected natural gas production hedged to fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf.  Our detailed hedge position is included in our Form 10-K filed yesterday afternoon.

Our annual results for our E&P segment were truly exceptional.  Operating income for this segment was $813 million in 2008, up from $358 million in 2007.  We grew our production by 71% to 194.6 Bcf equivalent and realized an average gas price of $7.52 an Mcf, which was up approximately 11% from the prior year.  Our lease operating expenses per unit of production were $0.89 per Mcf in 2008, up from $0.73 in 2007.  The increase was due primarily to increases in gathering and compression costs related to our operations in the Fayetteville Shale play, including the impact of higher natural gas prices on the cost of compression fuel.

General and administrative expenses per unit of production were $0.41 per Mcf in 2008, compared to $0.48 in 2007.  The decrease was primarily due to the effects of our increased production volumes, which more than offset increased compensation and related costs primarily associated with the expansion of our E&P operations.

We added a total of 219 new employees during 2008, most of which were in our E&P segment.  Taxes other than income taxes were $0.13 per Mcfe in 2008, down from $0.16 in the prior year due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes.

Our full-cost pool amortization rate dropped to $1.87 per Mcf in the fourth quarter and averaged $1.99 in 2008, down from $2.41 in the prior year.  The decline was due to the combined effects of our sales of oil and gas properties during the year, the proceeds of which were credited to the full-cost pool, and our low 2008 finding and development costs of $1.53 per Mcf⁽¹⁾.

Operating income from our Midstream Services segment also grew significantly in 2008 to $62.3 million, up from $13.2 million in 2007.  The increase was primarily due to higher gathering revenues and an increase in the margin from our marketing activities, partially offset by increased operating costs and expenses.  At February 15, we were gathering approximately 830 million cubic feet of gas per day through 864 miles of gathering lines in the Fayetteville Shale play area, up from approximately 405 million cubic feet a year ago.  

We worked very hard during 2008 on strengthening our balance sheet and improving our liquidity. In early 2008, we issued $600 million of 10-year 7.5% senior notes and used the proceeds to pay down our $1 billion revolving credit facility.  We believe our credit facility will provide us with a significant source of liquidity throughout its maturity in October of 2012, and it is not secured by any assets, and our ability to borrow is not tied to our reserves.

We ended the year with almost $200 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility, and had reduced our debt to capitalization ratio during the year from 37% down to 23%, or 19% net debt, and had total debt outstanding of $735 million at year-end.  We are well positioned to weather the current low commodity price environment with a strong balance sheet, excellent liquidity, and one of the lowest cost structures in our industry.

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

Questions and Answers

Operator: Thank you, sir.  Our first question comes from Tom Gardner with Simmons Company.  Please go ahead.  Your mic is open.

Tom Gardner: Good morning, everyone.

Harold Korell: Hi, Tom.

Tom Gardner: Hey.  Harold, I'd like to congratulate you on your retirement plans.  You leave quite a legacy at Southwestern and I have great respect and admiration for your accomplishments.  And Steve, congratulations on your promotion, and I know you and your team will have great success going forward.

Guys, impressive reserve additions this year.  Can you give me some help here peeling the onion with respect to your reserve revisions?  Essentially, you had about 100 Bcf net additions.  Can you give me an idea of upward performance revisions versus negative price related revisions embedded in that number?

Steve Mueller: For the total company, we had about 22 Bcf of negative price revisions.  And those were split pretty much evenly between Arkoma and East Texas.  Very little was in Desoto.  And then, total performance revisions were 120 Bcf total, that direction.

Tom Gardner: With respect to kind of individual average--I guess average uplift in bookings there on the Fayetteville wells, were those performance revisions primarily related to increasing the--or decreasing the terminal decline rate assumptions or just trying to get an idea?

Steve Mueller: Yes.  It's not really--we haven't done anything to the terminal decline.  What really happened, if you think about any given year, and 2008 is a perfect example, we started the year with one kind of completion technique.  We ended the year with another kind of completion technique and that's kind of why we gave the numbers where we went--that we talked about the last quarter.  Those wells are 2.2 Bcf.  When you started booking your PUDs, they do look at each pilot area, but they take the average in those pilot areas and really you're averaging the wells that have the most production.  So you're really seeing the weighted average for the first half of 2008 in your PUDs, and in 2007 it was the same kind of case.  So I think for the near future, as long as we keep our PUD, EUR, and our IPs increasing, you'll see positive revisions down the road as well.

Operator: And our next question comes from Jeff Hayden with Rodman and Renshaw.  Please go ahead, sir.  Your mic is open.

Jeff Hayden: Hi, guys.  Congratulations on the great quarter.  A couple quick questions.  One, I may have mentioned--I just wondered if you could give us a little color on how we should think about expenses going forward into 2009.  And then, also wondering kind of in the budget how many Marcellus wells do you have planned?

Greg Kerley: Well, on the--are you talking about overall drilling expenses or operating expenses, Jeff?

Jeff Hayden: Yes, just a kind of modeling number to show me how should we think about lifting cost per unit, kind of G&A going forward into 2009.

Greg Kerley: Okay.  Well, our guidance that we put out in December is still we think pretty solid.  We're going to end up trailing down on G&A from--we ended the year averaging $0.41, so we expect that to decline a little bit as our unit rates continue to increase.  Our taxes other than income taxes are going to be up a little bit from last year with the new severance tax in the state of Arkansas pushing that up a little bit.  Our amortization rate otherwise--on that side of those financial costs actually continue to trend down.  We were $1.87 in the fourth quarter.  With our finding costs at $1.53, that's going to help us and we expect to have some pretty good finding costs in 2009.  On our operating expenses, we still believe that around the $0.90 type--$0.90 to $0.95 range is a good number for us going forward.

Steve Mueller: As far as the Marcellus goes, we will probably participate in a couple of wells in the Marcellus, but we do not plan an active drilling program this year.  That will be more 2010. This year we'll concentrate on trying to pick up some more acreage and basically continue to block up for the position we have.

Jeff Hayden: Okay.  I appreciate it, guys.

Operator: And our next question comes from David Heikkinen with Tudor Pickering Holt.  Please go ahead sir.  Your mic is open.

David Heikkinen: Thank you.  Good morning.  A question on current strip in each one of your areas of operation.  Can you walk us through what your PVI metrics would be looking forward?  In the Fayetteville, 3 Bcf wells at 2.5, and then what you're doing in the James Lime, kind of where you're allocating capital.

Steve Mueller: I'll start--take a little bit of a stab at that, David.  We mentioned in our press release that we're dropping four rigs.  Both East Texas and Arkoma, the drilling we're going to be doing there, at least for the foreseeable future is for the most part holding acreage.  And those numbers are at--going for a 1.3 are challenged right now.  They're still making us good money, but they're not 1.3 PVI.  In the case of the Fayetteville shale, we're comfortable with today's prices that we can still average 1.3 PVI in the Fayetteville shale.  And so, what we plan to do is drop four total rigs.  We'll move one rig out of East Texas and one rig out of Arkoma and put that back into Fayetteville.  So while we have 15 big rigs running today, we'll exit the year with 13 rigs in the Fayetteville.

David Heikkinen: Okay.  And then, intrigued by your comments of putting more capital into the Haynesville/Bossierville.  How do you make that decision as far as more capital, less capital?  Driven by your partners willing to commit more capital to it or how does that kind of overall joint venture work?

Steve Mueller: I think the real thing is, as we've said, we're testing one well now and we've got one well drilling.  But we need to see the results of those wells and just figure out how economic they might be, and then we can figure out if we're going to put more capital into it.

David Heikkinen: Okay.  So just stay tuned on that?

Steve Mueller: Stay tuned--.

Harold Korell: --In reality it's a continuing story, because we're turning over cards and we have certain positions, we have partners, we have capital allocation sorting on projects, and we have an eye on our balance sheet as well.

Operator: Our next question comes from Joe Allman with JPMorgan.  Please go ahead, sir.  Your mic is open.

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

Harold Korell: Hi, Joe.

Joe Allman: Hey.  And congratulations to both of you guys.  And in terms of the Marcellus shale, you mentioned you have three wells that you production tested.  Do you want to--can you talk about the results there?

Steve Mueller:  The only thing we’ll say is we’re happy with the results. The reason we’re not giving out any data is that in Pennsylvania it’s very difficult to get production data. You know, some states within a month you have production data and in Pennsylvania that’s a little more difficult. So, part of the reason for drilling those wells, besides just testing our acreage was to give us some trade material that we could trade logs, production data, etc. and we’re doing that. And as long as that has value, you probably won’t see us saying much about the actual production.

Joe Allman: Okay, got you. And then in the Fayetteville shale, is it safe to say that some areas of the Fayetteville shale probably have average EURs at 3 Bcfe or above?

Steve Mueller: I guess the way to answer that question is in our PDP reserve base we have wells significantly above 3 Bcf, yes, already.

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

Brian Singer: I just wanted to check in on the commodity price environment here, you did tweak it down your budget slightly. Can you just talk to what commodity price environment that’s based on, and to the extent that natural gas prices stay at current or lower levels, what that would mean and regionally what the impact could be?

Steve Mueller: I’ll take an initial stab at this. Remember, we are hedged. We’ve got about half our 2009 production hedged at basically an $8.40 floor, so that helps us, especially in today’s price environment and we’ve done a lot of changes to the budget since we first announced it in December. I fully expect as the year goes through and you start watching the numbers and get a better feel for what’s going to happen, we’ll make more changes. The whole idea behind what we’re doing is to keep as flexible as possible and we’re still targeting that 1.3 PVI and we think with what we’re seeing today, we can still do that with where we have our capital being allocated.

Harold Korell: And I think as an addition to that, Steve, Brian, I would say that the thing to kind of keep in mind is that the wells that we’re drilling in the Fayetteville shale hit our PVI targets below $5.00 NYMEX price. And we’re fortunate to be in the position we're in, in the maturity of this play to have understood how to make it work and what makes it work and have our costs in line. And I want to differentiate that from what Steve said. We have hedges; the hedges help us with our cash flow to help us keep from moving our debt level higher since we are investing at a level above our cash flow. But, on the fundamental decision making part of it, the PVIs of these Fayetteville shale wells that we’re drilling, one could push those possibly down to the $4.00 NYMEX prices. So we find ourselves in a very enviable position and I don’t want to brag that we’re the best and greatest, but we actually are positioned at probably the most economic in today’s market and with our cost structure, probably the most economic shale play around.

Operator: Your next question is from Scott Hanold with RBC Capital Markets.

Scott Hanold: Steve, you had mentioned that the wells that you planned to drill that you said could average around 4,000 feet in lateral length. I just wanted to clarify that, because it was kind of interesting on your chart where you show sort of the performance and type curve reference points, wells that are above 4,000 foot lateral lengths appear to be following that 3 Bcf type curve. Can you kind of talk about what’s the expectation on average lateral length and what kind of ranges you’re looking at for 2009?

Steve Mueller: As we said, we’re going to average around 4,000 foot laterals. I think the longest lateral we’ve drilled to date is something over 5,500 foot and we’ve drilled a dozen or so wells in the 5,000 foot lateral range. Where we can do that, where the geology is set up that way, where we can do the units and get the exceptions, you’ll see us going to longer laterals. But in general, there are some other areas, for instance, when you get shallower that physically drilling a longer lateral just isn’t part of it, so part of it is just the mix when you start talking about the 4,000 foot laterals. We’ll get them out as long as we can, wherever we can.

Scott Hanold: Okay, so then if we look at that 78 well reference that you have over 4,000 feet, that’s a pretty reasonable way to look at your 2009 drilling program, is that a fair statement?

Steve Mueller: I would think so.

Scott Hanold: Okay, good. And then a quick follow-up as well for Greg. On severance taxes, could you just kind of talk to -- it looked like the fourth quarter severance tax dipped quite a bit and how do you think that’s going to look going into 2009, what’s the progression? I know the rate goes up as of 1-1, but will we see a pretty steep increase in the first quarter or is it going to sort of gradually roll in?

Greg Kerley: Well, it will gradually grow in and of course it will be affected by commodity price. Some of the mix last year in the drop in the fourth quarter was also due to some severance tax refunds we received in that helped lower us a few pennies on that average. But going forward, you have about a graduated rate in Arkansas that I think we figured it will be between 2% and 3% on average and a long-term going forward for a period of time, but we reflect it against whatever the commodity price environment is.

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

Gil Yang: Could you tell us how many wells were actually delayed from the fourth quarter to the first quarter and how many of those wells, in the first six weeks, what percentage of the wells that came on were actually those old wells?

Steve Mueller: There’s just over 50 wells that were delayed into 2009. It will take us well probably into the summer before those 50 wells or the equivalent of those 50 wells are all caught up. And the reason for that is we drove TD about 10 wells a week. We’re trying right now to complete about 11 to 12 wells a week, so it just takes 25 to 30 weeks to catch up. So, we’re in the process of doing that right now.

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

Mike Scialla: I wanted to echo the previous congrats to both Harold and Steven. Most of my questions have been asked, but just had one more for Greg. On the basis hedges, what could you hedge right now for Mid-Continent and do you have any plans to add to those?

Greg Kerley: We’ve got about the same amount pretty well tied to our commodity hedges right now, basis protection also at about close to 50% and I think we’re estimating that on average they’re about $0.55 to $0.60 on average differential. On a specific hub, each hub is a little different that you go to, but the worst field is CenterPoint and if you were going to try and do a basis say for the second quarter right now, it’d be something above $1.40 and then it decreases from there, depending which hub and which direction you’re going.

Mike Scialla: So really no plans to try and add at this point?

Greg Kerley: One of the things you need to remember is that somewhere around April 1st, the second phase of the Boardwalk Pipeline will be completed and we’ll be able to send gas across the Mississippi River and our basis will actually drop then, so we’ve been actively doing basis hedges actually more of the Eastern markets than CenterPoint market, because we’re planning to send as much gas as we can that way.

Operator: Your next question is from Marshall Carver with Capital One.

Marshall Carver: Congrats to both Harold and Steve. A couple of quick questions. Do you have any preliminary data on any downspacing tests in the Fayetteville?

Steve Mueller: We really don’t. We’ve kind of put together just around a 200 well program and we’re well into drilling it, but we’re just now starting to see the production results from that. It’s probably at least two quarters away before we’ll be able to get enough data where we can start sorting it out.

Marshall Carver: Okay, thank you. And on the Haynesville, could you give your most recent tally on acreage in the area, and have there been any nearby wells that also get you encouraged?

Steve Mueller: Our acreage is roughly 50,000 acres net that we have as Haynesville potential, as of what we’re seeing right now. There are some drilling wells around us that have TDed very comparable timeframe to what we’ve done and we haven’t seen any results -- we’re seeing a couple of them are completing right now, we haven’t seen results, so just the fact that people are completing wells gives you a little bit of benefit, but we haven’t seen anything.

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

Robert Christensen: Congratulations, Steve and Harold, for all the years of success. The Fayetteville, you still have some leases that have five years to hold them. Will you get that done? I mean, it looks like about 229,000 acres; it shouldn’t be too tough in five years, but what do you think there?

Steve Mueller: Of our drilling that we’re doing right now, about 40% of it is holding acreage and the other parts of it is really for the most part the downspacing testing that we’re doing. And this year we think we’re going to hold quite a bit of acreage. We’ll hold basically 180 to 200 wells, and then also we’re putting together a unit on some of the federal acreage and we’ll drill some wells there that should hold a big chunk of the federal acreage. So, this year will be a big year for us. We do have a plan over the next two to three years where we think we can hold all the acreage we want to hold.

Robert Christensen: Overton, South Overton, are there any rigs running there this year?

Steve Mueller: We’re actually completing right now a well in Overton area and that will be one of the rigs that’s going to move in the Fayetteville shale play, as we drop one of the rigs out of the Fayetteville. For the most part we’ll participate in a couple of outside operated wells; we don’t plan to operate much more in Overton this year.

Operator: Your next question is from Joe Allman with JPMorgan.  

Joe Allman: Thanks again. I’m going to throw out several questions, so maybe you have a pen or pencil there. So Steve, in response to an earlier question, I asked about 3 Bcf EUR and you said there are several wells booked well above that. Could you just address whether or not those are spread out in your acreage or is it in concentrated locations? And then could you talk about your gas, breakout the gas and which hubs gas is going to and what kind of throughput fees you pay? And then in terms of your reserve revisions, could you breakout the proved developed versus the PUD reserve revisions? And that’s all I’ve got.

Steve Mueller: As far as the 3 Bcf wells, they are anywhere where you’ve seen some fairly high IPs on wells that we’ve got, those are going to be where the big EURs are as well and they do go across the entire acreage that we have out there.

As far as gas on hubs, I’m not sure we need to go into a whole bunch of detail about that. I’d say over the near future, a good average number for us is in that 50% to 60% range and we’re working on whatever we can put basis on that gets it affected. As Greg said, we’ve got about 400 million a day that’s going into the Boardwalk Pipeline, and that’s an NGPL type marker. It is a little bit better basis; it’s a little less than $1.00 than the CenterPoint basis, but it’s still going Mid-Continent. Once that second phase gets turned around on April 1st, we should be able to scale up over 500 million a day of production going East, that basis will collapse. Right now it’s roughly neutral; $0.01 or $0.02 positive right now. So that’s the big swing for us is getting that 500 million a day around April 1st to go into the Eastern markets.

And then on the PDP versus the PUD revisions, I’ll have to give you that. We don’t have that right here.

Operator: Your next question is from David Heikkinen with Tudor, Pickering & Holt.

David Heikkinen: Actually, the question has already been answered. Thank you.

Operator: It appears there are no further questions in the queue. I’d like to turn the conference back over to Mr. Korell for closing remarks.

Harold Korell: Okay, well thank you all for joining us today and I look forward to seeing some or all of you on various conferences around the country in the next year. That concludes our comments. Thanks.

Operator: This concludes today’s conference. Thank you for your participation. You may now disconnect your line.

Explanation and Reconciliation of Non-GAAP Measures

(1) Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following reconciles F&D costs to the information required by paragraphs 11 and 21 of Statement of Financial Accounting Standard No. 69.

	For the 12 Months Ending December 31, 2008	For the 12 Months Ending December 31, 2007	Fayetteville Shale Play 2008
Total exploration, development and acquisition costs incurred ($ in thousands)	$ 1,559,995	$ 1,370,876	$ 1,191,558
Reserve extensions, discoveries and acquisitions (MMcfe)	920,181	507,855	824,706
Finding & development costs, excluding revisions ($/Mcfe)	$ 1.70	$ 2.70	$ 1.44
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)	1,018,281	538,830	983,635
Finding & development costs, including revisions ($/Mcfe)	$ 1.53	$ 2.54	$ 1.21

The company believes that providing a measure of F&D costs is useful for investors as a means of evaluating a company’s cost to add proved reserves, on a per thousand cubic feet of natural gas equivalent basis. These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Southwestern’s financial statements prepared in accordance with GAAP (including the notes thereto). Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded and development costs, including future development costs for proved undeveloped reserve additions, may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in Southwestern’s filings with the Securities and Exchange Commission, future F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern’s F&D costs may not be comparable to similar measures provided by other companies.

(2) Net cash provided by operating activities before changes in operating assets and liabilities - This measure is presented because of its acceptance 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. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. The table below reconciles net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.

	12 Months Ended December 31,
	2008	2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 1,167,494	$ 651,170
Add back (deduct):
Change in operating assets and liabilities	(6,685)	(28,435)
Net cash provided by operating activities	$ 1,160,809	$ 622,735

SWN Q4 08