Southwestern Energy Second Quarter 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 second quarter 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 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 had a very good second quarter in 2010 and made progress on many fronts. Our production grew by 32% compared to last year and grew by 9% sequentially, as our operations in the Fayetteville Shale are back on track. We have caught up to our original planned operated well count. The previously announced sale of a portion of our Haynesville and Middle Bossier properties in East Texas closed for approximately $355 million. Finally, because of our improving results in the Fayetteville, our production guidance is unchanged for the third and fourth quarters of 2010 and our capital investment program also remains unchanged at approximately $2.1 billion.

Fayetteville Shale Play

Now, to talk about each of our operating areas.  Last week, our gross operated production from the Fayetteville Shale reached over 1.4 Bcf per day, up from about 990 MMcf per day a year ago. During the second quarter of 2010, our horizontal wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 4,532 feet and average time to drill to total depth of 13 days from re-entry to re-entry. In the second quarter, we had 22 wells with drill times of over 20 days, most of which were first wells in sections that were in the deeper southern areas of the play. On the flip side, we placed 3 wells on production during the quarter with average times to drill to total depth of 5 days or less from re-entry to re-entry. In July of 2010, our average time to drill to total depth improved to 10 days from re-entry to re-entry, and we set a new record by drilling a well with a total footage of 6,600 feet in 4.0 days. Because of our recent faster drilling times, we are going to drop a horizontal rig in August, reducing our horizontal rig count to 15 rigs in the Fayetteville Shale.

Our Fayetteville wells placed on production during the second quarter of 2010 averaged initial production rates of 3,449 Mcf per day, up 8% compared to the first quarter. Results for the second quarter include 75 wells placed on production which were the first well in a new section. We also placed 9 wells on production at initial production rates over 6.0 MMcf per day.

We continue to test tighter well spacing and, at June 30, had placed over 430 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less. Recent information from this larger group of wells indicates interference of 5% to 8% compared to earlier estimates of 10% to 15% from a smaller well set. As you recall from last quarter, we are testing over 44 different pilots with well spacing that will range from 200 to 450 feet apart as part of our 2010 drilling program. Within those pilots, approximately 67% of the wells have been spud and 23% of those wells have been placed on production.

East Texas Field

Switching to East Texas, as I previously noted, on June 30th we closed the sale of certain oil and gas leases, wells and gathering equipment in Shelby and San Augustine counties for $355.8 million. The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,063 net acres. We retained the drilling and producing rights covering all other depths in the acreage, including our current James Lime and Pettet drilling programs.

We still have approximately 10,500 net acres with Haynesville and Middle Bossier Shale potential and drilled two wells on this acreage in the second quarter. The Timberstar Blackstone A-1H well targeting the Haynesville Shale formation has been drilled and is currently being completed and the Harris B-1H well targeting the Middle Bossier Shale formation has been drilled and is scheduled to be completed in November. A third well, the Crest C-1H, is currently drilling and will be completed in December.

Production from our East Texas properties was 19.2 Bcfe during the first six months of 2010, compared to 15.6 Bcfe during the same period last year. Approximately 2.1 Bcfe of our 2010 production was related to the Haynesville and Middle Bossier properties which were sold in June. Initial production rates from our James Lime wells that were placed on production during the quarter averaged 7.2 MMcfe per day and initial production rates from Pettet oil wells that were placed on production during the quarter averaged 505 barrels of oil per day, with 0.7 MMcf per day of associated gas.

Conventional Arkoma

In our conventional Arkoma Basin program, we participated in drilling 3 wells and production was 10.0 Bcf for the first six months of 2010, compared to 11.6 Bcf for the first six months of 2009.  One of those wells was the SWN-operated Johns #2-4H3 well in our Midway prospect area that was a 2,100-foot horizontal well in the Turner sand which had an initial production rate of 7.2 MMcf per day. We have a 60% interest in that well.

Appalachia

As we reported in the first quarter, we began drilling with one rig in Pennsylvania and have drilled 4 horizontal wells so far in 2010, all of which are currently scheduled to be completed in September. We expect to drill about 20 total wells this year. We also placed the Greenzweig #1-H well on production on July 8th and it is currently producing approximately 3.3 MMcf per day without compression into the pipeline with just over 3,000 psi of flowing tubing pressure. The Greenzweig well was our first horizontal well and was drilled in late-2008 with a 2,945-foot horizontal lateral and was fractured stimulated with slickwater in 7 stages. We are very encouraged about the early results of this well and look forward to our continued progress in the area as the year goes on. We also believe that the Marcellus in northeast Pennsylvania is rapidly developing into one of the best plays in the country. There are still many challenges from regulatory, logistics and environmental perspectives, but we fully expect those to be worked out over time.

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 earlier, we had a very good second quarter fueled by our strong production growth. We reported earnings for the second quarter of $122 million, or $0.35 per share, compared to $121 million in the same period in 2009.

We also reported discretionary cash flow of over $345 million, up 6% from last year, as our strong production growth more than offset the impact of lower realized gas prices and increased operating costs and expenses.  

Operating income for our E&P segment was $162.5 million for the second quarter, compared to $174.4 million for the same period in 2009. The decrease was primarily due to lower realized gas prices combined with increased operating costs and expenses, which were only partially offset by our higher production volumes.

We realized an average gas price of $4.27 per Mcf in the second quarter of 2010, down 15% from the prior year period.  Our commodity hedge position increased our average realized gas price by approximately $0.58 per Mcf in the second quarter and we currently have approximately 87 Bcf of our remaining 2010 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $6.26 per Mcf.   This represents a little over 40% of our expected production in the 3rd and 4th quarters.

During the quarter, we also increased our hedge position in 2011 and added some hedges in 2012.  We currently have 92 Bcf of our 2011 forecasted gas production hedged at an average floor price of $5.61 per Mcf and approximately 80 Bcf of our 2012 forecasted gas production at a floor price of $5.50 per Mcf.

Our lease operating expenses per unit of production were $0.85 per Mcfe during the quarter, compared to $0.73 last year.  The increase was primarily due to higher gathering costs and increased water disposal costs associated with our Fayetteville Shale play.  Higher water volumes, disposal rate increases and the use of more third-party disposal facilities all contributed to the increase during the quarter.  

Our general and administrative expenses per unit of production declined to $0.31 per Mcfe in the second quarter, down from $0.34 last year, due to the impact of our increased production volumes.  

Taxes other than income taxes were $0.09 per Mcfe in the quarter, compared to $0.08 in the prior year.

Our full cost pool amortization rate declined in the quarter, dropping to $1.33 per Mcfe, from $1.46 in the prior year, primarily due to lower finding and development costs.

Our total per unit operating cost and expenses (including LOE, G&A, Taxes and DD&A) was $2.64 per Mcfe in the second quarter, down from $2.67 in the prior year period.

Operating income from our Midstream Services segment increased by 57% to over $43 million in the second quarter.  The increase was primarily due to increased gathering revenues and an increase in the margin from gas marketing activities related to our Fayetteville Shale play, which were partially offset by increased operating costs and expenses.  At July 30th, our Midstream segment was gathering over 1.6 billion cubic feet of natural gas per day through 1,367 miles of gathering lines in the Fayetteville Shale play, compared to approximately 1.1 billion cubic feet per day a year ago.  Included in our gathered volumes is approximately 170 million cubic feet per day of third-party gas, which has more than doubled since the beginning of the year.

To update you on the Fayetteville Express pipeline, they are making very good progress and we currently expect interim service to NGPL as early as October of this year and full service commencing on or about January 1, 2011. Our initial firm capacity on the pipeline will be 400 million cubic feet per day on January 1, 2011, increasing to 1.2 Bcf per day by November 2011.

We invested approximately $1 billion in the first six months of 2010, compared to $959 million in the same period last year.  At June 30, we had $506 million borrowed on our $1 billion credit facility at an average interest rate of 1.2%, and had total debt outstanding of $1.2 billion.  This leaves us with a debt to book capital ratio of 31% and a debt to market capitalization ratio of only 9%.  

As Steve mentioned, during the second quarter we closed on the sale of a portion of our East Texas properties and have deposited the net proceeds of approximately $355 million with a qualified intermediary to facilitate potential like-kind exchange transactions.  

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 reconciliation below of GAAP net cash provided by operating activities to non-GAAP net cash provided by operating activities before changes in operating assets and liabilities for the three months ended June 30, 2010 and June 30, 2009.

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.