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): March 1, 2006

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Arkansas

(State or other jurisdiction of incorporation)

1-8246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 300, 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 March 1, 2006, at 10:00am Eastern, Southwestern Energy Company will host a telephone conference call for investors and analysts.  The prepared teleconference comments are furnished herewith as Exhibit 99.1.

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

Exhibit Number	Description
99.1	Prepared teleconference comments for March 1, 2006 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: March, 1, 2006	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Prepared teleconference comments for March 1, 2006 telephone conference call for investors and analysts.

EX-99

Exhibit 99.1

Southwestern Energy Fourth Quarter and Year-End 2005 Earnings Teleconference

Speakers:

Harold Korell; President, Chairman and Chief Executive Officer

Richard Lane; Executive Vice president and President of the company’s Exploration and Production business

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell: Good morning, and thank you for joining us.  With me today are Richard Lane, the President of our Exploration and Production segment and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of the press release we announced yesterday regarding our 2005 financial results, you can call Annie at (281) 618-4784 and she’ll fax a copy to you.  Also, I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings.  We also would warn you that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control.  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.

2005 was an outstanding year for Southwestern Energy.  For the third consecutive year we set new records for annual production volumes, reserve replacement and year-end reserve levels.  And, as a result, our financial results were outstanding as we delivered new records for earnings and cash flow, and our balance sheet is the strongest it’s ever been. In addition, and importantly, we have positioned the company well for the future with our Fayetteville Shale play in Arkansas and exposure to the emerging Barnett play in the Permian Basin.

On the operating side of our E&P business, we are continuing to move forward with our plan to evaluate our large acreage position in the Fayetteville Shale play.  Our first company-owned rig began drilling in January, with success, and we will be increasing our activity as the year goes forward.  As time goes by, we are accumulating the production data that will be the key to understanding and for projecting the estimated ultimate recoveries for our Fayetteville Shale wells.  

Up to now, the focus of our play in Arkansas has been the Fayetteville Shale, and it likely will continue to be this way.  However, in addition, within the last 3 months we have produced gas from the slightly deeper Moorefield and Chattanooga Shales.

So, as the year unfolds, we will be continuing to increase our knowledge about the different aspects of the unconventional play in Arkansas and will begin to gather data on our position in the Permian. I’d like to now turn the teleconference over to Richard Lane, who will tell you more about our E&P activities, then to Greg Kerley to discuss our financial results.

Richard Lane: Thank you and good morning. In 2005, we set new records for our annual production and reserves additions.  Gas and oil production totaled 61.0 Bcfe, up 13% from 54.1 Bcfe in 2004. The increase in 2005 production resulted primarily from the continued development of our Overton Field in East Texas, and from increased production from our Fayetteville Shale play in Arkansas.

Production for the 4th quarter of 2005 was 15.7 Bcfe, up from the 15.1 we produced in the 4th quarter of 2004. Our production during the quarter was lower than originally expected due to delays in the Company’s drilling programs caused by rig problems.  Of the 15.7 of 4th quarter production, 8.1 was from East Texas, 4.9 from our conventional Arkoma Basin properties, 1.4 from the Permian Basin, 0.8 from the Gulf Coast Region, and 0.6 from the Fayetteville Shale.  We estimate that our 1st quarter 2006 production will be between 15.7 and 16.1 Bcfe and that full-year 2006 production will be 74.0 to 76.0 Bcfe.

We ended 2005 with 826.8 Bcfe of total proved oil and gas reserves, up 28% from 645.5 at year-end 2004.  In 2005, we added 243.1 Bcfe of proved reserves including revisions.  Of the 826.8 Bcfe of year-end 2005 reserves, 368.7 were in East Texas, 271.0 in the Arkoma Basin, 101.0 in the Fayetteville Shale, 58.6 in the Permian Basin, and 27.5 in the Gulf Coast Region.  We replaced 399% of our 2005 production at a finding and development cost of $1.71/Mcfe including revisions and excluding the capital invested in drilling rigs.  Excluding revisions our finding and development cost was $1.51/Mcfe.  Proved developed reserves accounted for approximately 73% of the total and our reserve life index was 13.6 years.  

In 2005, we invested $451.3 million in our exploration and production program and participated in drilling 247 wells.  Of the 247 wells, 197 were successful, 8 were dry, and 42 were in-progress at year-end for an overall success rate of 96%.   Of the $451.3 million invested in 2005, approximately $323.1 million was for drilling wells, $60.6 million was for leasehold acquisition and seismic, $35.1 million was for the purchase of drilling rigs, and $32.5 million was for other capitalized costs. Excluding the capital we invested in new drilling rigs, approximately 78% of our 2005 E&P investments were in drilling.

Fayetteville Shale Play

In our Fayetteville Shale Play in 2005,  we invested approximately $154.5 million, including $67.4 million to spud 67 wells, $40.7 million for leasehold acquisition, $35.1 million toward the fabrication of ten new drilling rigs to be utilized in the play, $4.3 million for seismic, and $7.0 million in capitalized costs.  

We continue to increase our significant lease holdings in the play and as of February 27th, we held a total of approximately 875,000 net acres in the play area.  Of this, approximately 750,000 net acres were in the undeveloped play area and the remaining 125,000 net acres were in the traditional “Fairway” area of the Arkoma Basin that is held by production.

From the beginning of our drilling program in the Fayetteville Shale in 2004 through February 27, 2006, we have spud a total of 117 wells in the play, 112 of which were operated by us and five of which were outside-operated wells.  The wells are located in 17 separate pilot areas located in seven counties in Arkansas and, as of Monday, 60 were producing, 17 were in some stage of completion or waiting on pipeline hook-up and 6 were shut-in due to marginal performance or temporarily abandoned.  The remaining 34 wells are in the drilling phase.   We estimate that the wells drilled to date have demonstrated that the Fayetteville Shale is gas productive over an area approximately 100 miles by 20 miles.

Sixty-three of the 117 wells spud are horizontal wells.  As of February 27th, 17 of these were producing, 11 were completing, 4 were drilling, 2 were temporarily abandoned and 29 wells had been drilled through the vertical section.  The average initial test rate for 16 of the 17 completed horizontal wells is 2.2 MMcf per day, excluding our first horizontal well in which problems with wellbore isolation limited the stimulation treatment.  The well costs for the most recent horizontal wells have ranged from $1.4 million and $1.8 million per well, excluding non-recurring costs.  The horizontal wells drilled through December 31, 2005, have had an average vertical depth of 3,200 feet and an average lateral length of 2,000 feet, and have taken 15 to 20 days on average to reach total depth.  During 2006, we plan to test longer lateral lengths to determine the optimal wellbore design.

In yesterday’s earnings release, we included an average well production plot compared to our 1.3 Bcf and 1.5 Bcf typecurves.  While there is a wide range of performance from individual horizontal wells, in aggregate, the average well production data plots roughly between the 1.3 to 1.5 Bcf typecurves.  Two of our more recently completed horizontal wells, the McNew #4-2-H in our Gravel Hill Field and the Church #1-27-H in our Griffin Mountain Field are only included in the production data for 125 and 95 days, respectively.  The McNew #4 was our first horizontal to be stimulated with a slickwater frac.  The Church #1 utilized a hybrid slick-water and nitrogen foam fracture stimulation.  Both of these wells are producing at rates exceeding the average horizontal well and are tracking above our typecurves.  To further test these stimulation techniques, we plan on using either slick wa ter or hybrid fracture stimulations in several horizontal wells as we go forward.

Net gas production from the Fayetteville Shale play during 2005 was 1.8 Bcf, compared to 0.1 Bcf produced during 2004.  Proved gas reserves booked in the play as of year-end 2005 were 101.0 Bcf from 177 locations, of which 54 were proved developed producing, 6 were proved developed non-producing and 117 were proved undeveloped.  Of the 177 locations, 131 were designated as horizontal wells.  Our estimated average ultimate recovery from these wells is 1.3 to 1.5 Bcfe per horizontal well.  The average proved reserves for each of the horizontal undeveloped locations included in our audited year-end reserves was approximately 0.95 Bcfe gross per well, or 63% to 73% of our estimated ultimate recovery.  This is a reasonable and prudent percentage given the relatively short production histories of these wells, and following best practices for proved reserves estimating, we fully expect our booked reserve estimates to increase over time.

As you know, we have an audit done of our reserves each year by an outside reserve engineering company.  For the past four years we have used Netherland & Sewell to do this audit.  Again this year, NSA audited our reserves and gave us their audit opinion which states “the estimates of total proved reserves and future revenue are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.”  In doing their audit work, NSA expresses their findings in aggregate regarding the Company’s reserve bookings and does not give us specific analysis in report form for each of our fields.  This year we did, however, inquire of NSA what their value was for our horizontal wells in the Fayetteville Shale Play.  In discussions with us, NSA has indicated that their current estimate of average proved reserves for the horizontal wells in the shale play is 700 MMcfe although they generally believe that their reserve estimates for these wells will increase over time.  We continue to believe, based upon our modeling and early production data, that horizontal wells in the play will have estimated ultimate recoveries of 1.3 to 1.5 Bcfe per well.

We currently have four rigs running in our Fayetteville Shale Play.  Of these four rigs, one is a “shallow” rig which we use to drill the vertical portion of our wells prior to moving in one of the three larger rigs capable of drilling the horizontal section.  By utilizing shallow rigs, we have built an inventory of 29 wells ready to be deepened.  Additionally, we currently have 14 pre-built locations on to which we will be moving our shallow rigs.

As we announced last year, we have entered into sales agreements with a private company to build a total of ten new land drilling rigs capable of drilling the horizontal wells in the Fayetteville Shale Play.  We took delivery of our first rig in late January.  The DeSoto Drilling Inc. Rig #1 has already successfully drilled its first two horizontal wells.  We expect to take delivery of the second rig in early March and to have all ten of the rigs drilling in the 4th quarter of 2006.  Combining these rigs with additional contracted drilling rigs, we expect to have three shallow rigs and up to 14 deeper rigs in the play at the end of this year.  In conjunction with ramping up the number of drilling rigs in the Fayetteville Shale play, we also now have access to a second set of completion equipment and crews dedicated to the play.  We anticipate further increases in dedicated completion s ervices as we progress throughout 2006.

In addition to our Fayetteville Shale potential, we have tested gas production from the deeper Moorefield and Chattanooga Shales that are also found in our play area.  Our Carter #1-35, a vertical well, located in our East Cutthroat pilot area in Cleburne County, was completed in the Moorefield Shale and tested at 710 Mcfpd.  Based on our preliminary work in some areas, the Moorefield Shale, which underlies the Fayetteville Shale, has similar reservoir characteristics.  We currently hold approximately 130,000 net acres that we believe may be prospective in the Moorefield Shale.  We expect to put the Carter well on production in early March.  The Carter #1-35 had 220’ of gross Fayetteville Shale and 85’ of gross Moorefield Shale.

Additionally, we are currently testing the Chattanooga Shale in the Eschbach #1-12 after fracture-stimulating the well.  The Eschbach well is located in our traditional “Fairway” held-by-production acreage. The Chattanooga Shale occurs below both the Fayetteville and Moorefield Shales.  The Eschbach #1-12 penetrated approximately 100’ of gross Fayetteville Shale, and 50’ gross Chattanooga Shale.

In 2006, we expect to invest $338.3 million in the Fayetteville Shale play, which would include drilling between 175 to 200 wells.  Of those wells, nearly all will be horizontal wells.  In 2006, we will focus on increasing our production through development drilling while also determining the extent of the Fayetteville Shale by testing the undrilled portion of our acreage in an additional 24 to 30 pilot areas.  

Arkoma Basin Conventional

In 2005, we invested approximately $64.5 MM in our conventional Arkoma Basin, drilling 71 wells, of which 61 were successful and 5 were in progress at year-end.  We added 51.7 Bcfe of proved reserves, including revisions, in the Arkoma Basin.  Our 2005 production from the Arkoma Basin was 20.2 Bcfe, relatively flat compared to 2004’s production of 20.1 Bcfe.

In 2005, we further increased our drilling activity at our Ranger Anticline Project Area in Yell and Logan Counties, Arkansas. During 2005, we successfully completed 34 out of 37 wells (excluding three wells in progress at year-end 2005), which added 19.3 Bcf of new reserves at a finding and development cost of $2.19 per Mcf, including downward reserve revisions of 4.0 Bcf.  Excluding reserve revisions, our finding and development cost at Ranger was $1.81 per Mcf.  Net Ranger production in 2005 was 5.6 Bcfe, approximately 60% higher than the 3.5 Bcfe we produced in 2004.

Our wells at Ranger have primarily targeted the Upper and Lower Borum tight gas sands between 5,000 and 8,000 feet in depth.  In 2005, wells completed in the Borum had average estimated ultimate gross reserves of 1.2 Bcf per well.  

In 2005, we extended the field boundaries to the east approximately 9 miles by completing four successful wells in shallower Basham, Nichols and Turner gas sands.  These shallower sands are between 3,500 and 4,500 feet in depth and had average estimated ultimate reserves of 0.5 Bcf per well.  Average costs to drill and complete these shallow wells have been approximately $700,000.  

Late in the third quarter of 2005, we drilled the initial exploratory well on our Midway prospect, targeting the Pennsylvanian and Ordovician sections.  The USA #1-24 well encountered approximately 230’ of net pay by electric log calculation in the Pennsylvanian age Borum sands, which is the main producing horizon in the Ranger Anticline area.  We are currently testing these sands and will determine the development potential based on the results.  We have approximately 20,300 gross undeveloped acres in our Midway prospect area.

In 2006, we plan to invest approximately $89.6 million in the conventional Arkoma program to drill approximately 100 to 110 wells, including 50 to 60 wells at the Ranger Anticline.  We also plan to have a significantly increased workover program, particularly in the traditional Fairway area of the Arkoma Basin, targeting the recompletion of behind-pipe productive intervals.

East Texas Field

In 2005, we invested approximately $183.6 million in East Texas, drilling 89 wells.  Of this, $158.0 million was invested in our Overton Field where we drilled and completed 80 wells, of which 52 were 40-acre spaced wells.  We added 91.2 Bcfe of proved reserves, including revisions, in East Texas.  Our 2005 production of 28.2 Bcfe from East Texas was 27% greater than the 22.2 Bcfe we produced in 2004.

We continue to maintain a 100% success rate at Overton after drilling 253 wells since we acquired the field in 2000.  Daily gross production at the Overton Field increased to approximately 109.7 MMcfe at year-end 2005 resulting in net production of 26.7 Bcfe during 2005, compared to 21.8 Bcfe in 2004.  New wells drilled in the field during 2005 averaged approximately $1.8 million to drill and complete, had average initial production rates of approximately 3.0 MMcfe per day and had average estimated ultimate gross reserves of 1.8 Bcfe per well.  In 2006, we plan to invest approximately $161.5 million at Overton and drill approximately 83 wells.  

In addition to Overton, we continue to expand our holdings at the Angelina River Trend in Nacogdoches County, Texas.  At December 31, 2005, we held approximately 11,000 gross undeveloped acres and 3,000 gross developed acres.  Since this time, we have signed a letter-of-intent to acquire an additional 9,600 gross acres.

Through December 31, 2005, we had drilled nine wells with 100% success in this trend primarily targeting the Travis Peak formation.  Net production from the area was 0.9 Bcfe in 2005.  Gross initial production rates from wells drilled during 2005 ranged from 1.7 to 4.4 MMcfe per day.  The average estimated ultimate recovery from the wells completed in 2005 is expected to be approximately 1.6 gross Bcfe per well with an average drill and complete cost of $2.5 million per well.  In 2005, we invested $18.7 million in the Angelina River Trend.  During 2006, we intend to invest $34.5 million to drill a total of 16 wells in the area.

Exploration and New Ventures

Along with our Fayetteville Shale Play and our on-going East Texas and Arkoma Basin drilling programs, we continue to develop new prospects for future development.  At the end of 2005, we held approximately 116,600 net undeveloped acres, primarily in the Rocky Mountain Area and Permian Basin, associated with other conventional and unconventional natural gas and oil plays.   Of this, approximately 50,000 acres are located in Culberson County, Texas, in the emerging Barnett Shale play in the Permian Basin.  We anticipate spudding our first test well here during the 2nd quarter.

In 2006, we plan to invest approximately $28.9 million in exploration projects and $14.5 million in New Venture projects, including drilling up to 18 wells in the continental United States.

Summary

In summary, we are very pleased with our record results in 2005.  Our program is performing well, delivering significant growth in production and reserves, while achieving our investment return target of 1.3 PVI or greater.  In 2005, we developed a better understanding of the individual well potential of our Fayetteville Shale Play.  In 2006, we expect to develop a fuller understanding of the Play’s potential size.  

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

Greg Kerley: Thank you, Richard, and good morning.  As Harold indicated, 2005 was an excellent year for Southwestern.  We ended the year with record fourth quarter earnings of $48.9 million, or $0.29 per share, compared to $32.9 million, or $0.22 per share for the same period in 2004.  Our net cash provided by operating activities before changes in operating assets and liabilities was $102.8 million during the fourth quarter of 2005, up 42% from $72.4 million in the fourth quarter of 2004.  Strong commodity prices and higher production led to the improved financial results.

For the full-year of 2005, we reported record net income of $147.8 million, or $0.95 per share, up 43% from $103.6 million, or $0.70 per share in 2004.  Net cash provided by operating activities before changes in operating assets and liabilities also set a new record in 2005 at $321.8 million, up 35% from $237.7 million in 2004.

Operating income for our E&P segment was $234.8 million in 2005, compared to $164.6 million for the same period in 2004.  The average price realized for our gas production, including the effects of hedges was $6.51 per Mcf in 2005, up from $5.21 a year ago.  

Our current hedge position, which consists primarily of costless collars, provides us with significant support for a strong level of cash flow in 2006.  The average floor price of our collars is approximately $5.50 per Mcf and provides a solid base for our projects, while the average ceiling price of approximately $10.00 still allows us to retain considerable upside.  Approximately 70 to 75% of our targeted gas production and 15 to 20% of our targeted oil production is hedged in 2006.

Disregarding the impact of our commodity price hedges, the average price received for the company’s gas production during 2005 was approximately $0.90 per Mcf lower than average NYMEX spot prices, due to locational market differentials, compared to an average of $0.34 per Mcf during 2004.  We have approximately 75% of our basis differentials protected for 2006.  Assuming an average $8.00 per Mcf MYMEX commodity price and including the effects of our current basis hedges, we expect our average realized market differentials to be approximately $0.60 to $0.70 per Mcf lower than average NYMEX spot market prices for 2006.

Our average realized oil price in 2005 was $42.62 per barrel, compared to an average price of $31.47 per barrel in 2004.  We expect the average price received for our oil production to be approximately $1.50 per barrel lower than average spot market prices, excluding the impact of any commodity price hedges.  

Our lease operating expenses per unit of production were $0.48 per Mcfe in 2005, up from $0.38 in 2004.  The increase in 2005 was due primarily to increases in compression, saltwater disposal and gas processing costs, as well as generally higher oilfield service costs.

Taxes other than income taxes per unit of production were $0.37 in 2005, compared to $0.28 in 2004.  The increase in 2005 was due to increased severance and ad valorem taxes that primarily resulted from higher commodity prices.

General and administrative expenses per Mcfe were $0.46 in 2005, compared to $0.36 in 2004.  The increase was due primarily to increased payroll costs due to the expansion of our E&P operations related to the Fayetteville Shale play and higher incentive compensation costs.  The number of employees in our E&P segment increased to 280 at December 31, 2005, up from 147 at the end of 2004.  Our full cost pool amortization rate averaged $1.42 per Mcfe in 2005, compared to $1.20 in 2004.

Operating income for the utility was $4.9 million in 2005, down from $8.5 million last year.  The decrease resulted from increased operating costs and expenses and reduced usage per customer due to customer conservation brought about by high gas prices and warmer than normal weather.  Effective October 31, 2005, the Arkansas Public Service Commission approved a rate increase for our gas utility that will increase future revenue and operating income by approximately $4.6 million annually.

Operating income from our midstream services segment was $5.7 million in 2005, up from $3.2 million in 2004.  The increase in 2005 was primarily due to higher marketing margins on natural gas sales caused in large part by the increased volatility of locational market differentials in our core operating areas.

Midstream services also had gathering revenues of $1.0 million in 2005 related to gathering systems it owns in Arkansas.  Gathering revenues for this segment are expected to continue to grow in the future as gathering systems for the company’s Fayetteville Shale play are constructed to support the development of this play.  

We also earned interest income of $3.4 million related to our cash investments in 2005.

Our financial position, simply put, is the best in the company’s history.  Our strong earnings, along with our equity offering in September 2005 (in which we raised approximately $580 million), helped us to decrease our balance sheet debt-to-capitalization ratio to 8% at year-end 2005, down from 42% at December 31, 2004.  And, more importantly, we have positioned the company to allow us to aggressively pursue the development of our Fayetteville Shale play.

Our planned capital investments for 2006 are $830.1 million, consisting of $770.3 million for exploration and production, $37.5 million of midstream services, $11.9 million for gas distribution system improvements and $10.4 million for general purposes.  Our 2006 capital investment program is expected to be funded through cash flow from operations, the remaining net proceeds from our equity offering, and borrowings under our revolving credit facility.  From this capital program, we are targeting 2006 oil and gas production of 74 to 76 Bcfe. Our targeted production in the first quarter of 15.7 to 16.1 Bcfe is up slightly from our fourth quarter production, however as we continue to implement our drilling program we expect our production levels to ramp up significantly in the last half of the year.

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