Southwestern Energy Fourth Quarter and Year-End 2006 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 - CEO, President, Chairman

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 fourth quarter and year-end 2006 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.  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.

As we look back on 2006, it was an amazing year.  For the fourth consecutive year we set new records for annual production volumes, year-end reserves, earnings and cash flow – and our balance sheet is in great shape.  

Despite operational challenges, we successfully grew our Fayetteville Shale production volumes from 9 MMcf per day to 100 MMcf per day by year-end.  Today, our Fayetteville Shale volumes are at approximately 120 million cubic feet per day gross and could reach up to 300 million per day by year-end 2007.  During the year, we also created our own drilling company which now operates 13 newly-built drilling rigs in our Fayetteville Shale program.  This allowed us to go from 3 drilling rigs operating in the play at the beginning of 2006 to 19 rigs at year-end.  

Our operational challenges and the hiring of nearly 500 new employees to help carry out our increased operating activities impacted our cost structure and our results during 2006. However, the investments we made to accelerate the play have set the stage for substantial growth in our production and reserves in 2007.

In the Fayetteville Shale play, we are now producing gas over an area that encompasses approximately 45% of our 892,000 net acres.  So, we know it is a very large resource.  We will continue to aggressively assess and develop our acreage in the play during 2007 as we invest about $875 million to drill between 400 and 450 horizontal wells and shoot 3-D seismic over a large portion of the acreage.  The result of all this, we believe, will be stimulating growth in our production and reserves.  We look forward to relating our progress to you as the year unfolds.

I will now turn the teleconference over to Richard for an update on our operations and then to Greg for a discussion of our financial results.

Richard Lane – EVP and President of E&P Operations

Good morning. In 2006, we set new records for our annual production and reserves additions.  Gas and oil production totaled 72.3 Bcfe, up 19% from 2005, as a result of increased production from our Fayetteville Shale and East Texas wells. Our Fayetteville Shale production alone was 11.8 Bcf in 2006, up substantially from the 1.8 produced in 2005.

Production for the 4th quarter of 2006 was 20.7 Bcfe, up 32% from the 15.7 we produced in the 4th quarter of 2005.  Our production from the Fayetteville Shale increased to 5.5 Bcf during the 4^th quarter, up from 0.6 in the 4^th quarter of 2005.   We estimate that our 1^st quarter 2007 production will be between 20.0 and 21.0 Bcfe and that full-year 2007 production will be 105 to 110 Bcfe.

We reached a significant milestone as we ended 2006 with just over 1 Tcfe of total proved oil and gas reserves, up 24% from 827 Bcfe at year-end 2005.  The 1.03 Tcfe of year-end 2006 reserves are approximately 37% in East Texas, 27% in the conventional Arkoma Basin, 29% in the Fayetteville Shale and 7% in other areas.   

In 2006, we added 365.5 of proved reserves and replaced 386% of our 2006 production at a finding and development cost of $2.75 per Mcfe including 86.6 Bcfe of negative revisions and excluding the capital invested in drilling rigs.  The downward proved reserve revisions were primarily due to a comparative decrease in year-end gas prices, combined with performance revisions in our East Texas and Arkoma Basin properties, which were partially offset by an upward performance revision in our Fayetteville Shale properties.  Excluding revisions, our finding and development cost was $2.10 per Mcfe.  Proved developed reserves accounted for approximately 65% of our total reserves at year-end 2006.  

In 2006, we invested $767 MM in our primary exploration and production business activities and participated in drilling 382 wells.  Additionally, we invested $94 MM related to the purchase of drilling rigs which were sold in December 2006 as part of a sale and leaseback transaction.  Of the 382 wells, 230 were successful, 9 were dry, and 143 were in-progress at year-end for an overall success rate of 96%.   Of the $767 MM invested in 2006, approximately $617 MM was for drilling wells, $70 MM was for leasehold acquisition and seismic, $18 MM was for producing property acquisitions, and $62 MM was in other capitalized costs. Excluding the capital we invested in new drilling rigs, approximately 80% of our 2006 E&P investments went to drilling wells.

Fayetteville Shale Play

In our Fayetteville Shale Play in 2006, we invested approximately $388 MM, including $316 MM to spud 196 wells, $29 MM for leasehold acquisition, $14 MM for seismic, and $29 MM in capitalized costs.  

At the end of 2006, we held a total of approximately 892,000 net acres in the play area of which 51,000 net acres are held by Fayetteville Shale production and 125,000 net acres are held by conventional production in the traditional Arkoma Basin Fairway.  Excluding the Fairway acreage, our acreage position has an average lease term of 7 years, and an average royalty interest of 15%.  Our cumulative “all-in” average acreage cost is $95 per acre.

Gross production from our operated wells in the Fayetteville Shale play increased from approximately 9 MMcf per day at the beginning of 2006 to approximately 100 MMcf per day by year-end, and could reach near 300 MMcf per day by the end of 2007.  As of February 26^th, our production rate has increased to approximately 120 MMcf per day, on track with our plan. We currently expect our total 2007 net production from the Fayetteville Shale to range from 45.0 to 50.0 Bcf, compared to 11.8 Bcf during 2006.

Our total proved gas reserves in the Fayetteville at year-end 2006 were 300 Bcf, compared to 101 Bcf at the end of 2005. Proved developed reserves from our horizontal wells range from 0.2 Bcf to 2.8 Bcf per well and the average gross proved undeveloped reserves per well included in the company’s year-end reserves was approximately 1.15 Bcf per well, up approximately 20% from 0.95 Bcf per well at the end of 2005.  We currently estimate that the average ultimate gross production for these wells will be 1.3 to 1.5 Bcf per horizontal well.

We currently have three completion crews operating in the area which are keeping pace with our drilling operations.  We have continued to test various completion techniques, including using crosslinked gel and slickwater fluid treatments as well as various downhole mechanical equipment. Not all of these techniques have proven to be successful and have impacted the performance of some of our recent wells. However, we continue to experiment with new completion techniques, fluid systems and longer lateral lengths to further optimize the performance of wells.  In the 1^st quarter, we plan to drill 14 wells with lateral lengths greater than 3,000’, as compared to our average 2006 lateral length of 2,300.

In yesterday’s earnings release, we included an update of our normalized average daily production data through February 26, 2007, for the company’s horizontal wells using slickwater and crosslinked gel fluids. The “light blue” curve includes all wells, and the “dark blue” curve excludes nine wells which had significant mechanical issues that are negatively impacting the wells’ production performance. The normalized production curves provide a qualitative measure of the company’s Fayetteville Shale wells’ performance but should not be used to estimate an individual well’s estimated ultimate recovery. The 1.3 and 1.5 Bcf typecurves shown on the graph reflect the range of the company’s current estimates of the expected performance of the average horizontal well completed in the Fayetteville Shale with either a slickwater or crosslinked gel fracture stimulation and are based on production history currently available.

As of February 26, 2007, we had 19 drilling rigs running in our Fayetteville Shale play area, 15 of which are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical section of the horizontal wells. We have been able to mitigate a portion of higher service costs through the utilization of its surface hole drilling program and increased efficiencies from its new fit-for-purpose drilling rigs. In 2006, the company averaged 18 days from re-entry-to-re-entry (including moving between locations) utilizing the combination of the smaller rigs and larger rigs, and we expect this time to be reduced to approximately 16 days during 2007. We currently plan to continue to utilize at least 19 rigs in the play area through 2007 and we anticipate well costs for completed horizontal wells drilled in 2007 will be approximately $2.3 million per well.

While drilling several of our Fayetteville Shale wells, we have begun to encounter conventional sand reservoirs.  At South Rainbow, the Loui Prince #1-22 was dually completed in the Upper and Lower Hale reservoirs and is currently producing 2.7 MMcf per day.  We anticipate that the data we receive from our 3-D seismic program will be a beneficial tool toward uncovering more of the conventional targets.

In 2007, we plan to invest $875 million in our Fayetteville Shale play, which includes drilling between 400 and 450 horizontal wells and shooting 3-D seismic over a large portion of our Fayetteville Shale acreage. We currently have 2 seismic crews in the field and have begun collecting data.  Based on our previously acquired 3-D pilot programs, we believe 3-D seismic has the potential to optimize well performance, minimize geologic risk, and better guide extended lateral length drilling. We also plan to drill up to seven horizontal wells in the Moorefield Shale and one horizontal well in the Chattanooga Shale.

Arkoma Basin Conventional

In 2006, we invested approximately $97 MM in our conventional Arkoma Basin, drilling 84 wells, of which 54 were successful and 26 were in progress at year-end. We added 51.6 Bcfe of proved reserves in the Arkoma Basin which were partially offset by downward revisions.  Our 2006 production from the Arkoma Basin was 20.1 Bcfe, relatively flat compared to 2005’s production of 20.2 Bcfe, while proved reserves totaled 277 Bcf at year-end, up slightly from 271 Bcf at year-end 2005.

At our Ranger Anticline area located in Logan and Yell Counties, Arkansas, we successfully completed 27 out of 29 wells during 2006 excluding 17 wells in progress at year-end. Much of our drilling last year at Ranger Anticline focused on the area located between the main producing part of the field and the eastern extension where we drilled several wells in 2005.  One well of note in this area is the Smith #1-12, which has produced approximately 1 Bcf gross since being put on production in August.  We operate this well, which is currently producing 4.5 MMcf per day with a 75% working interest.  Additionally, we are currently completing the Bryant #1-7.  This well has tested at rates of 7.0 MMcf per day.  We expect to put this well, which we operate with a 48% working interest, on production within the next few weeks.  Since drilling our first successful well at Ranger in 1997, we have successfully drilled 104 out of 118 wells, adding 95.7 net Bcf of reserves at a finding cost of $1.52 per Mcf, including reserve revisions. We believe that Ranger holds significant future development potential and could have more than 150 remaining potential locations.

During 2006, we drilled five offsets to the USA #1-24, one of our 2005 discovery wells on our Midway prospect.  Four of these wells are producing while the remaining wells are waiting on pipeline connection.  At December 31, 2006, we held approximately 28,650 gross acres in our Midway prospect area and, depending on the performance of the newly drilled wells, we plan to drill up to 15 wells here in 2007.  Midway is located in Logan County and is approximately eleven miles north of Ranger. We operate all of these wells with an average working interest of 60%.  

In 2007, we plan to invest approximately $116 million in the conventional Arkoma program and drill approximately 100 to 110 wells, including 50 to 60 wells at Ranger.

East Texas

In 2006, we invested approximately $204 MM in East Texas, and drilled and completed 78 wells.  Of this, $155 MM was invested in our Overton Field where we drilled and completed 66 wells.  The remaining 12 wells were drilled and completed in our Angelina River Trend play.

In East Texas we added 92.8 Bcfe of proved reserves, which were partially offset by downward revisions, in 2006.  Production of 32.0 Bcfe was 13% greater than the 28.2 Bcfe we produced in 2005.

We continue to maintain a 100% success rate at Overton after drilling over 300 wells since we acquired the field in 2000.  New wells drilled in the field during 2006 averaged approximately $2.3 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 1.6 Bcfe per well.  Most of our 2007 Overton drilling program will focus on drilling proved undeveloped locations.

In addition to Overton, we continue to expand our holdings at the Angelina River Trend located primarily in Nacogdoches County, Texas.  At December 31, 2006, we held approximately 68,900 gross undeveloped acres and 6,400 gross developed acres.  This acreage includes a new farm-in that we negotiated in late 2006 for approximately 16,500 gross acres from a major oil company.  Our first test of this farm-in block, which we call our Jebel Prospect, is scheduled for the second quarter of 2007.  

Through the end of last year, we had drilled a total of 28 wells in the Angelina River Trend primarily targeting the Travis Peak formation.  This play consists of eight separate blocks of acreage. During 2006, a large portion of our drilling activity consisted of evaluation of our acreage position where we defined some poorer and some better areas for development.  This ultimately lowered our overall well performance, but defined the areas we will focus on in 2007.  In one of our high-graded areas, Doyle Creek, we completed wells in 2006 with average reserves of 1.5 Bcf/well.  We expect our 2007 results to be better as we continue to high-grade our drilling program.  

In total in 2007, we plan to invest approximately $163 MM in East Texas, including drilling approximately 39 wells at Overton and approximately 28 wells in the Angelina River Trend 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 2006, we held approximately 89,600 net undeveloped acres, associated with other conventional and unconventional natural gas and oil plays.   

In 2006, we invested approximately $46 MM and drilled a total of seven exploration wells, of which two tested gas, two were dry, and three were in progress at year-end.  The two dry holes were conventional tests in the Rocky Mountains area.  

In 2006, we completed two wells in our Permian Basin Barnett Shale play where we hold approximately 50,000 acres in Culberson County, Texas.  One well was shut-in for a pressure build-up test after testing non-commercial quantities of gas.  The other well is currently waiting on a pipeline connection to prior  conducting an extended production test to determine the viability of additional drilling.  We expect to have better determined the prospectivity of our Permian Barnett acreage by the end of 2007.

The three remaining wells which were in progress at year-end were in our Silver Water Coal Bed Methane project in Caldwell Parish, Louisiana.  Here, we have approximately 11,000 net acres in the project area targeting the Tertiary-age Lower Wilcox coals at a depth of approximately 2,800 feet.

In addition to these plays, we are developing what looks to be a sizable non-operated position in the Woodford Shale play in eastern Oklahoma.  We hold 20,800 net prospective acres in the play and have already drilled 3 wells.

In 2007, we plan to invest approximately $58 MM in our Exploration and New Ventures projects, including drilling up to ten wells in the Woodford Shale in Oklahoma and up to 30 wells in our Silver Water project.

Summary

In summary, we are very pleased with our record results in 2006.  We continue to be very encouraged by our success in our Fayetteville Shale project and our programs in the Arkoma Basin and East Texas are performing well.  We are looking forward to continued strong results in 2007 including meeting or exceeding our PVI target, 40 to 50% 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 – EVP and CFO

Thank you, Richard, and good morning.  We reported record net income of $162.6 million in 2006, up 10% from the prior year.  Our operating cash flow (defined as cash flow from operating activities before changes in operating assets and liabilities) also set a new record increasing to $413.5 million, up 29% from 2005, largely driven by a 19% increase in our production volumes.  We also ended the year with an extremely strong balance sheet, as our outstanding debt represented only 9% of our total book capitalization.

Our earnings for the fourth quarter were $33.8 million, or $0.20 per share, down from $48.9 million, or $0.29 per share, in 2005, as the positive effect on our earnings of an increase in production was more than offset by a 19% decline in natural gas prices and increases in operating costs. Net income for the fourth quarter of 2006 also included a $3.3 million loss accrual related to the settlement of outstanding litigation. Our operating cash flow was $108.7 million in the fourth quarter, up from $102.8 million in 2005, as our production growth more that offset the effects of lower gas prices and higher cash operating costs.

Operating income for our E&P segment was $237.3 million in 2006, compared to $234.8 million in 2005. We produced a total of 72.3 Bcfe in 2006 and approximately 94% of our production was natural gas. The average price realized for our gas production, including the effects of hedges was $6.55 per Mcf in 2006, compared to $6.51 a year ago.  Our hedging activities increased our average gas price realized during the year by $0.18, compared to a decrease of $1.22 in 2005.

Our current hedge position, which consists of fixed price swaps and costless collars, provides us with support for a strong level of cash flow in 2007.  Since our last conference call we have significantly increased our hedge position and currently have approximately 80 Bcf hedged in 2007 and 57 Bcf in 2008.  In 2007, the average price of our natural gas fixed price swaps is $7.81 per Mcf and the average floor price of our collars is approximately $7.00, both of which provide a solid base for our projects, while the average ceiling price on our collars is over $12.00 allowing us to retain considerable upside.  Approximately 75% of our 2007 targeted gas production is currently hedged.  In 2008, the average price of our natural gas fixed price swaps is $8.26 per Mcf and the average floor price of our collars is approximately $8.00.

Our average realized oil price in 2006 was $58.36 per barrel, compared to an average price of $42.62 in 2005.  

Our lease operating expenses per unit of production were $0.66 per Mcfe in 2006, up from $0.48 in 2005.  The increase was due primarily to increases in gathering and other costs related to our operations in the Fayetteville Shale.  We expect our per unit lease operating cost to range between $0.82 and $0.87 per Mcfe in 2007 due to increased production volumes from the Fayetteville Shale play.

Taxes other than income taxes were $0.30 per Mcf in 2006, down from $0.37 in the prior year.  In 2007 we expect our rate to range between $0.21 and $0.26 per unit of production.

General and administrative expenses per unit of production were $0.58 in 2006, compared to $0.46 in 2005.  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 increased incentive compensation costs.  We hired a total of 494 new employees during 2006, including approximately 300 in our drilling company.  We expect our general and administrative expenses per unit of production to decrease in 2007 and range between $0.41 and $0.46 per Mcfe as a result of our projected production growth.

Our full cost pool amortization rate averaged $2.16 per Mcfe in the fourth quarter and averaged $1.90 for the full year.  The increase during 2006 was primarily due to higher finding and development costs.  We expect our amortization rate to range between $2.15 and $2.25 per Mcfe in 2007.  Going forward our finding and development costs and amortization rate are both expected to be heavily impacted by the timing and amount of reserve bookings in our Fayetteville Shale play.

Operating income from our midstream services segment was $4.1 million in 2006, compared to $5.7 million in 2005.  The decrease was primarily due to increased operating costs and expenses related to our rapidly expanding gas gathering activities and a decline in the margin generated by our gas marketing activities.  We expect our midstream services segment to generate approximately $10 to $12 million of operating income in 2007 as our gas gathering activities in our Fayetteville Shale play continue to expand.

During 2006, we entered into several firm transportation agreements aimed at ensuring market access for our growing Fayetteville Shale production volumes.  Our agreements with Ozark Gas Transmission System increase to 270,000 MMBtu per day over the next two years and, for the long-term, we are arranging for transportation on two newly-proposed pipeline laterals and related facilities of Texas Gas Transmission, LLC.  Once the pipelines have been approved, we will enter into firm transportation agreements that will enable us to transport up to 500,000 MMBtu per day, with the option to acquire up to 300,000 MMBtu per day of additional capacity. Depending on regulatory approvals, the expected in-service date for the laterals is January 1, 2009 and our agreements would have initial terms of 10 years.

Operating income for our utility was $4.5 million in 2006, down from $4.9 million last year. The decrease resulted primarily from warmer weather and increased operating costs partially offset by increased rates implemented in October 2005. Our utility filed an application for a general rate increase last fall, and any increase approved is expected to take effect in July 2007.

We have recently completed a couple of key financings that have further strengthened our financial condition and liquidity. In December, we entered into a sale and leaseback transaction through which we sold 13 drilling rigs and related equipment owned by us to various financial institutions and then leased these rigs and equipment back, along with two additional new drilling rigs and equipment that we had ordered.  We received $127.3 million in cash for the 13 rigs and related equipment and recorded a deferred gain of $7.4 million which will be amortized over the lease term.  Also, earlier this month, we amended our unsecured revolving credit facility increasing our borrowing capacity from $500 million to $750 million, and lowering our borrowing costs to 87.5 basis points over LIBOR.  The amount available under the credit agreement can also be increased by up to an additional $250 million in the future.  

Our new credit agreement substantially decreases our current borrowing costs and provides us with flexibility in executing our planned capital investment program over the next few years. At December 31, 2006, we had total indebtedness of only $138 million and we had no borrowings under our revolving credit facility.  Our capital structure at year-end consisted of 9% debt and 91% equity.

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

Southwestern Energy Company Fourth Quarter and Year-End 2006 Earnings Teleconference Transcript

March 1, 2007