Southwestern Energy Second Quarter 2011 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 second quarter 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, we are excited to report one of the best quarters ever for our Company. We posted outstanding growth in earnings, cash flow and production in the second quarter, despite the low gas prices we have experienced. Our production continues to grow, primarily driven by our Fayetteville Shale operations, however we are also beginning to see the impact of our Marcellus Shale activities on our production where operated production from the Marcellus Shale is over 100 MMcf per day from 17 horizontal wells.  Total production growth was 25% during the quarter, fueled by our Fayetteville Shale play which grew by 28% with production of 107 Bcf. We also produced 5.1 Bcf from the Marcellus Shale, 6.3 Bcfe from East Texas and 4.0 Bcf from our Arkoma Basin operations.

Finally, we announced a new potential unconventional horizontal oil play and hope to get two test wells drilled and completed by year-end.

Fayetteville Shale

Now, to talk about each of our operating areas.  We placed 149 operated wells on production in the Fayetteville Shale during the first quarter, which resulted in gross operated production reaching approximately 1.8 Bcf per day at July 25.

Our operated horizontal wells had an average completed well cost of $2.8 million per well with an average drilling time of 8.2 days during the second quarter.  We also placed 10 wells on production during the quarter that were drilled in 5 days or less. In total, we have drilled 55 wells to date in 5 days or less.  

Our average initial producing rates were approximately 3.0 million cubic feet per day, which is down from the first quarter primarily due to slightly shorter laterals, locational differences in the mix of wells and more pad drilling which creates additional well interference and uneven loading of compressors.  Our lowest average production this quarter was in April, where we put 55 wells on production at an average initial rate of 2.7 million cubic feet of gas per day.  These numbers improved during the quarter and by June our average initial production rate was 3.4 million cubic feet of gas per day.

Marcellus Shale

In Northeast Pennsylvania, we are very encouraged by what we have seen to date.  At June 30, we had completed 17 operated Marcellus Shale horizontal wells in our Greenzweig area in Bradford County. Net production from the area was 5.1 Bcf in the second quarter of 2011, compared to 2.8 Bcf in the first quarter and 0.8 Bcf in the fourth quarter of 2010. In May, we initiated compression on 7 wells and this reduced the average line pressure on those wells by 600 to 650 psi. The other 10 wells, however, are currently producing without the benefit of compression into line pressures of over 1,000 psi. Gross operated production from this area is currently approximately 104 MMcf per day.  

We continue to place several wells on production from a single pad at the same time and the results continue to be strong. However, one specific well of interest is the Ball Myer 1H well, which we placed on-line in June. This well had a completed lateral of 4,500 feet and was fracture stimulated in 19 stages and is currently producing at a tubing constrained rate of approximately 7.8 MMcf per day at a flowing tubing pressure of 1,400 psi after 33 days of production. Prior to this well, our horizontal wells have had average lateral lengths of approximately 3,900 feet and have averaged 10 stages of completion. Going forward, our future horizontal wells are expected to average 12 to 13 stages per well with estimated completed well costs for those wells of $5.0 to $5.5 million per well.

In August, we will be moving a 2nd rig up to Pennsylvania to begin drilling in our Range Trust area in Susquehanna County. For the remainder of 2011, we expect to drill 3 wells in the Greenzweig area, 9 wells in the Range Trust area, 10 wells in the Price area and 2 wells in Lycoming County. The majority of these wells will be placed on production in 2012.

New Ventures

Switching to New Ventures, in New Brunswick we are on schedule to drill at least one well in the second half of 2012.  We have started the acquisition of approximately 410 miles of 2-D data and hope to have that finished in September. We are also in the second phase of geochem acquisition which will provide more information on potential hydrocarbon generation.  That work should be completed next month.  Early in 2012, we will shoot a tighter grid of 2-D seismic to help give us a better understanding of where to drill our first well.

Outside of New Brunswick, we currently have approximately 835,000 net undeveloped acres in connection with other New Ventures prospects. Of these 835,000 net acres, we have approximately 460,000 net acres where we will begin testing a new unconventional horizontal oil play targeting the Lower Smackover Brown Dense formation.  This acreage amount, incidentally, happens to be almost the same number of acres we had when we announced the Fayetteville Shale back in August of 2004.

The Brown Dense is an unconventional oil reservoir found in southern Arkansas and northern Louisiana.  It ranges in vertical depths from 8,000 to 11,000 feet, is laterally extensive over a large area and ranges in thickness from 300 to 550 feet. Our investment in undeveloped acreage in the play area to date is approximately $150 million and our leases currently have an 82% average net revenue interest. We will be targeting the more mature, higher gravity oil under our lease area which we believe could be in the 40 to 55 API range, if successful.  

The formation is an Upper Jurassic age, kerogen-rich carbonate source rock which covers an area from Texas to Florida. We extensively reviewed the Brown Dense across the region and have indications that the right mix of reservoir depth, thickness, porosity, matrix permeability, sealing formations, thermal maturity and oil characteristics are found in the area of Southern Arkansas and Northern Louisiana. Porosity ranges from 3% to 10% in the area and the anticipated pressure gradient is 0.62 psi/ft, so it is over-pressured. Estimated matrix (unenhanced) permeability based on various methods of measurement ranges from 0.068 millidarcies to 1.17 millidarcies. Both porosity and matrix permeability are comparable to metrics reported in the Eagle Ford play in South Texas.

We have assembled log data on 1,145 wells covering 5 states to evaluate the Brown Dense, have acquired over 6,000 miles of 2-D seismic data and have gathered and analyzed rock data from cores and cuttings from 70 wells that penetrated the Brown Dense. At this point, we currently have more data about the Brown Dense than we had on the Fayetteville Shale when it was announced.

We hope to receive a permit to drill our first well in Columbia County, Arkansas, in August and will spud later in the third quarter. This well is planned to drill to a vertical depth of approximately 8,900 feet and has a planned horizontal lateral length of 3,500 feet. The well will be extensively logged and a full core is planned over the entire Brown Dense interval before the well is completed. The completed well cost of this first well is estimated to be around $10 million, which more than $2 million is science work.

Our second well is planned to spud later this year with a total vertical depth of approximately 10,700 feet and a 6,000-foot horizontal lateral in Claiborne Parish, Louisiana.  

We plan to drill up to 10 additional wells in 2012 as we continue to test the concept. This formation has sourced several large conventional oil and gas fields and our hope is to use horizontal drilling technology to unlock at least as much potential. Positive test results could significantly increase our activity in this play over the next several years.

We are also working on other New Ventures ideas and will provide updates on those in the future.

Other Areas

Finally, in East Texas, we sold certain oil and natural gas leases, wells and gathering equipment in Shelby, San Augustine and Sabine Counties for approximately $108 million, before customary purchase price adjustments. This divestiture included only the producing rights to the Haynesville and Middle Bossier Shale intervals in this acreage with net production of approximately 7 MMcf per day as of May 25, 2011 and proved net reserves of approximately 25.1 Bcf at December 31, 2010. We have deposited $85 million of proceeds from this sale to facilitate potential like-kind exchange transactions.      

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.  As Steve noted, our financial and operating results for the quarter were some of the best in our history.

We reported earnings for the second quarter of $167 million, or $0.48 per share, which was a 37% increase from the prior year period.   Our discretionary cash flow was a record $448 million in the second quarter, up 30% from $346 million for the same period in 2010. The comparative increases in earnings and cash flow were primarily due to the growth in our production volumes that Steve spoke about earlier.

Our results stand out even more when you consider that our average realized gas price was comparatively flat with the same period last year. We realized an average gas price of $4.30 per Mcf in the second quarter compared to $4.27 per Mcf a year ago. Our hedging activities helped to increase our average gas price by $0.46 per Mcf during the second quarter. We have continued to increase our hedge position, and in the last few months we hedged an additional 56 Bcf for 2011 at an average price of $5.11 per Mcf, 40 Bcf for 2012 at an average price of $5.01 per Mcf and 60 Bcf for 2013 at an average price of $5.16 per Mcf. As a result, we currently have NYMEX price hedges in place on notional volumes of 160 Bcf, or over 60%, of our remaining 2011 gas production at a weighted average floor price of $5.21 per Mcf.  

Operating income for our E&P segment was $223 million during the quarter, up 37% compared to $163 million in the same period last year.  Our cost structure continues to be a huge benefit and it remains one of the lowest in our industry. Our all-in cash operating costs, which include lease operating expenses, general and administrative expenses, taxes other than income taxes and net interest expense, were $1.23 per Mcfe for the second quarter of 2011.  

Our full cost pool amortization rate also declined, dropping to $1.28 per Mcfe in the quarter, from $1.33 in the prior year.  The decline in the average amortization rate was primarily the result of the sale of certain East Texas oil and natural gas leases and wells in late 2010 and 2011, as the proceeds from the sales were appropriately credited to the full cost pool, combined with lower finding and development costs.

Operating income from our Midstream Services segment was $60 million in the first quarter, up 36% from the prior year period.  The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses.  At June 30th, our Midstream segment was gathering approximately 2.0 billion cubic feet of natural gas per day through 1,696 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 1.6 billion cubic feet per day a year ago.  

As you may recall, we have been considering various strategic alternatives for our Fayetteville Shale gathering assets. We have been deliberate in our analysis, however we have not yet made a decision on which alternative, if any, we should pursue.

At June 30, we had $544 million borrowed on our $1.5 billion credit facility at an average interest rate of around 2.16%, and had total debt outstanding of a little more than $1.2 billion, resulting in a debt to book capital ratio of 27% and a debt to market capitalization ratio of only 7%.  

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.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended June 30, 2011 and June 30, 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.