Southwestern Energy Fourth Quarter and Year-End 2010 Earnings Teleconference

Speakers:

Steve Mueller; President and Chief Executive Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Steve Mueller; President and Chief Executive Officer

Good morning, and thank you for joining us. With me today are Greg Kerley, our CFO, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday’s press release regarding our fourth quarter and year-end 2010 results, you can find a copy on our website at www.swn.com.  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 the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin, 2010 was a record year for Southwestern Energy.  Despite lower realized gas prices, we set new records in 2010 for production, reserves, earnings and cash flow. We posted production growth of 35% fueled by our Fayetteville Shale play, where our production grew 44% to 350 Bcf.  We also produced 34 Bcfe from East Texas, 19 Bcf from the Arkoma Basin and 1 Bcf from the Marcellus Shale which we kicked off late in the year.

Our year-end proved reserves also increased by 35% to a record 4.9 Tcfe.  Approximately 100% of our reserves were natural gas and 45% were classified as proved undeveloped, down from 46% in 2009.  We again recorded net positive reserve revisions during the year, primarily due to the improving performance from our Fayetteville Shale wells and positive price revisions due to higher average gas prices.

We replaced 430% of our 2010 production at a finding and development cost of $1.02 per Mcfe, including revisions.  Our cost structure is the key in the current gas price environment, as our finding and development costs and production costs are among the lowest in our industry.

Fayetteville Shale Play

Now, to talk a bit about our operating areas.  The Fayetteville Shale continues to deliver exceptional results.  Our 2010 drilling program in the Fayetteville added 1.6 Tcf of new reserves at a finding and development cost of $0.86 per Mcf.  This includes net upward reserve revisions of approximately 273 Bcf, due to improved well performance and positive revisions due to higher average gas prices.  Our finding and development cost in the Fayetteville excluding these revisions was $1.04 per Mcf.  

Total proved net gas reserves booked in the Fayetteville Shale play at year-end 2010 were 4.3 Tcf, up 39% from reserves booked at the end of 2009.  The average gross proved reserves for the undeveloped wells included in our year-end 2010 reserves was approximately 2.4 Bcf per well, up from 2.2 Bcf per well at year-end of 2009, and based upon our current drilling pace, we have approximately 3 years of drilling inventory booked as PUDs.

We spud 658 wells in the Fayetteville Shale during 2010 and placed a record 553 operated wells on production. We continued to improve our drilling and completion practices, as our operated horizontal wells had an average completed well cost of $2.8 million per well, compared to an average of $2.9 million per well in 2009. The decrease in our drilling times and other savings and benefits from our vertical integration have more than offset longer average lateral lengths.  Our average initial producing rates were approximately 3.4 million cubic feet per day compared to last year’s 3.5 million cubic feet average rate. During 2010, 40% of our operated wells were drilled along the periphery of the field as the first well in a section, which created a significantly different mix of wells compared to our 2009 results.  

As for an update on our spacing tests, at year-end 2010 we had drilled nearly all of our well spacing tests and over 80% of these wells are currently on production. We expect to have additional production data by the end of the first quarter of 2011 on the remaining 40% of our acreage where more results were needed. In addition, we are in the process of performing interference testing on certain of our closer-spaced areas.

Appalachia

Switching to Pennsylvania, we invested approximately $118 million in Pennsylvania during 2010 and participated in 21 wells, of which 6 were successful and 15 were in progress at year-end. These 6 wells are all operated horizontal Marcellus Shale wells located in our Greenzweig area in Bradford County that production tested between 4 and 8 MMcf per day. We placed 3 additional operated horizontal wells on production on February 18, all of which were located in the Greenzweig area. Total daily gross operated production from the area is currently approximately 45 MMcf per day without compression, with flowing tubing pressures ranging from 1,100 to 1,300 psi and choke sizes ranging from 23/64” to 40/64”. The wells we are currently completing have average lateral lengths of approximately 4,500 feet and are averaging 7 to 10 frac stages.

We anticipate our Marcellus activity to grow substantially in 2011 with 1.5 rigs running in 2011 compared to only 1 rig running for 10 months last year. We plan to invest approximately $265 million in Appalachia, which includes participating in a total of 40 to 45 wells, all of which will be operated.  

East Texas Field

In our East Texas operating areas, we invested approximately $150 million and participated in 25 wells, of which 17 were successful and 8 were in progress at year-end. In June of 2010, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $358 million which included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,000 net acres.

We retained approximately 10,000 net acres which we believe is prospective for the Haynesville and Middle Bossier Shale intervals. Our first Middle Bossier test on this acreage, the Harris B-1H well, was placed on production on February 9th with a 14-stage frac.  The well has cleaned up nicely following a restricted flowback program and reached an initial production rate of 9 MMcf per day at 7,900 psi on a 17/64 choke on the 11th day of the flow back.

Conventional Arkoma

In our conventional Arkoma Basin program, we invested $13 million and only participated in 9 wells. In 2011, we will continue concentrating on the Fayetteville and Marcellus and again reduce the amount we plan to invest here, and in East Texas.

New Ventures

As for New Ventures, at December 31, 2010, we held over 3 million net undeveloped acres in connection with our New Ventures prospects, of which a little over 2.5 million net acres were located in New Brunswick, Canada and the remaining approximately 490,000 net acres are located in the U.S.

In March of 2010, we announced that the Department of Natural Resources of the Province of New Brunswick, Canada had accepted our bids for exclusive licenses to search and conduct an exploration program in the province in order to test new hydrocarbon basins.  In 2010, we invested approximately $10 million of the required $47 million to be invested in the province over the next three years. In January of this year, we received initial information from a geochemical survey we had conducted during 2010. Nearly 2,000 samples were taken in more than 35 traverses. All of the traverses had signatures indicating some combination of oil and gas source rocks. Most of our 2011 activity in New Brunswick is shooting 370 miles of regional 2-D seismic and performing more geo-chem work.

In 2010, we invested a total of approximately $145 million in our New Ventures programs and in 2011 we plan to invest approximately $170 million in New Ventures, which includes drilling in at least one new area.  

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

Greg Kerley – Executive Vice President and Chief Financial Officer

Thank you, Steve, and good morning.  I am very pleased to report that 2010 was the best year in the company’s history from a financial perspective.  

For the calendar year, we reported net income of $604 million, or $1.73 per share, up 16% from last year’s adjusted net income.  Cash flow from operations (before changes in operating assets and liabilities) was $1.6 billion, up 10% compared to last year. Our earnings and cash flow both set new records for the company, as our production growth of 35% more than offset the effect of significantly realized lower natural gas prices.  

Our annual results for our E&P segment were truly exceptional. Operating income for our E&P segment was $829 million, compared to $750 million (excluding a non-cash ceiling test impairment) in 2009.   For the year, we grew our production by 35% to 404.7 Bcfe and realized an average gas price of $4.64 per Mcf, which was down from $5.30 per Mcf in 2009.  

We increased our commodity hedge position over the last few months and currently have 186 Bcf, or approximately 40%, of our 2011 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $5.30 per Mcf.  Our hedge position, combined with the cash flow generated by our Midstream business which is not dependent on gas prices, provides protection on approximately 55% of our total expected cash flow for 2011. Our detailed hedge position is included in our Form 10-K filed this morning.

We continue to have one of the lowest cost structures in our industry, with all-in cash costs of approximately $1.30 per Mcf in 2010, and a 3-year average of $1.35 per Mcf.  When you include our finding and development costs, our full-cycle costs were $2.32 in 2010 and $2.42 for the 3-year average.  

Our lease operating expenses per unit of production were $0.83 per Mcfe in 2010, compared to $0.77 in 2009. The increase was primarily due to increased gathering and compression costs and increased costs related to higher water disposal volumes in our Fayetteville Shale play.

Our general and administrative expenses per unit of production declined to $0.30 per Mcfe in 2010, down from $0.35 in 2009.  The decrease was primarily due to the effects of our increased production volumes which more than offset the effects of increased compensation and other employee-related costs primarily associated with the expansion of our operations in the Fayetteville Shale.

Taxes other than income taxes were $0.11 per Mcfe in both 2010 and 2009.

Our full cost pool amortization rate also declined during 2010 to $1.34 per Mcfe, down from $1.51 in the prior year.  The decline was due to a combination of our low finding and development costs, the ceiling test impairment recorded in the first quarter of 2009, and the sale of natural gas and oil properties in the second quarter of 2010, as sales proceeds were credited to the full cost pool.

Operating income from our Midstream Services segment rose 56% to $192 million in 2010 and EBITDA for the segment was $221 million.  The increase was primarily due to increased gathering revenues related to the Fayetteville Shale play and an increase in the margin from our gas marketing activities. At December 31, 2010, our Midstream segment was gathering approximately 1.8 Bcf per day through 1,569 miles of gathering lines in the Fayetteville Shale play, compared to gathering 1.3 Bcf per day a year ago. Our gathering system for the Fayetteville Shale play has developed into a strategic asset that not only supports our E&P operations but enhances our overall returns.  We are currently considering various strategic alternatives for recognizing and maximizing the value of this asset.

We strengthened our balance sheet during 2010 and our long-term debt-to-total capitalization ratio declined to 27%, down from 30% at year-end 2009. At December 31, 2010, we had approximately $1.1 billion in long-term debt including $421 million borrowed on our revolving credit facility.  On February 14, we amended and restated our credit facility which was scheduled to expire in February 2012.  The maturity date was extended to February 2016 and the borrowing capacity was increased to $1.5 billion up from $1.0 billion with an accordion feature that permits us to increase the facility to $2.0 billion with agreement of existing or new lenders. We believe our credit facility will provide us with a significant source of liquidity for the next several years.  It is a totally unsecured facility not tied to a reserve borrowing base.

We invested $2.1 billion during 2010, compared to $1.8 billion in 2009, and we currently expect that our total capital investments for 2011 will be approximately $1.9 billion. There is clearly uncertainty today regarding natural gas prices, so our capital plans will remain flexible.  

In summary, 2010 was an exceptional year for us as we posted record results, both from an operational perspective and a financial perspective. We are uniquely positioned to weather the current gas price environment with a strong balance sheet, excellent liquidity and one of the industry’s lowest cost structures.

We are fortunate to have the largest position in one of the most profitable plays in the country, and we look forward to adding even greater value for our shareholders through our positions in the Fayetteville and the Marcellus and our new exploration plays. That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Explanation and Reconciliation of Non-GAAP Financial Measures

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

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

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

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the twelve months ended December 31, 2010.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

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 computes F&D costs using information required by GAAP for the twelve months ending December 31, 2010.

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 and the SEC’s 2009 adoption of a number of revisions to its oil and gas reporting disclosure requirements, 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 SEC, 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.