Southwestern Energy Third 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 third 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 an excellent third quarter. Despite lower gas prices, our earnings and cash flow were up significantly compared to last year. This increase was primarily driven by our production growth of 44% compared to last year and 7% sequentially.  

We also are beginning to better understand the well spacing for the Fayetteville Shale play, and I will speak more about that in a moment.

Fayetteville Shale Play

Now, to talk about each of our operating areas. During the third quarter, our gross operated production from the Fayetteville Shale reached over 1.5 Bcf per day, up from approximately 1.2 Bcf per day a year ago, and also surpassed the net production mark of 1 Bcf per day. During the third quarter of 2010, our horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,503 feet and average time to drill to total depth of 11 days from re-entry to re-entry. We continue to see faster drilling times, and in the third quarter, we had 8 wells placed on production which had average times to drill to total depth of 5 days or less from re-entry to re-entry. Our horizontal rig count stands at 13 rigs compared to the 15 drilling rigs we averaged during the first nine months of 2010.

The 145 Fayetteville wells placed on production during the third quarter of 2010 averaged initial production rates of 3,281 Mcf per day, down 5% compared to the second quarter. Results for the third quarter include 58 wells (or 40%) placed on production which were the first well in a new section and 36 wells (or 25%) drilled to test tighter well spacing. We also set a new record during the third quarter by placing the play’s highest rate well, the Harlan 09-10 #1-12H located in Cleburne County, on production with an initial production rate of approximately 8.7 MMcf per day. This well had a completed lateral length of 3,874 feet and a 9-stage fracture stimulation. After 34 days, it is still producing 5.7 MMcf per day.

We continue to test tighter well spacing and, at September 30, 2010, had placed over 520 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less. Previously, we have stated that based on the wells drilled to date, we expected a minimum of 10 to 12 wells per section to effectively drain the reserves, which would represent approximately 65-acre spacing. However, early production performance from recent well spacing tests indicates that there are areas of the field that may be economically developed at tighter spacing. At this time, we have confirmed that approximately 20% of the roughly 600,000 net acres drilled to date can be developed at 30- to 40-acre spacing, approximately 40% can be developed at 65-acre spacing and the remaining 40% requires additional results to determine if development on tighter spacing than 65-acres would be economic. We will continue with our well spacing program to better define the areas of the field that are suitable for tighter spacing and expect to know more about well spacing on the remainder of our acreage in 2011.

East Texas Field

Switching to East Texas, production from our East Texas properties was 26.9 Bcfe during the first nine months of 2010, compared to 24.6 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.

We still have approximately 10,500 net acres with Haynesville and Middle Bossier Shale potential and have drilled three wells on this acreage to date. The Timberstar Blackstone A-1H well targeting the Haynesville Shale formation was placed on production in August at an initial production rate of 13.2 MMcf per day. The other two wells which are targeting the Middle Bossier will be completed in the first quarter of 2011.

Conventional Arkoma

In our conventional Arkoma Basin program, production was 14.8 Bcf for the first nine months of 2010, compared to 16.9 Bcf for the first nine months of 2009.  

Appalachia

In Pennsylvania, we have drilled 9 horizontal wells, 3 of which are currently being completed, and we expect results from those wells sometime next month. Approximately 15 wells are expected to be drilled by year-end, 7 of which are expected to be completed by year-end.

You may remember that in July we placed our first well in Pennsylvania on production, the Greenzweig #1-H, and, at our second quarter earnings release date, it was producing approximately 3.3 MMcf per day without compression into the pipeline with just over 3,000 psi of flowing tubing pressure. Since that time, we cleaned out the wellbore, and, post-cleanout, the well reached a peak rate of over 5.0 MMcf per day in September and is currently producing at 2.8 MMcf per day with approximately 1,900 psi of flowing tubing pressure. The Greenzweig had 2,945 feet of completed lateral and was fractured stimulated with slickwater in 7 stages; so this is very encouraging. The wells we are currently completing will have average lateral lengths of approximately 4,500 feet and have several more frac stages.

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, our results for the third quarter were excellent. Earnings for the quarter were up 36% to $161 million, or $0.46 per share, compared to $118 million in the same period in 2009.

We also reported discretionary cash flow of over $421 million, which was up 27% from last year and set a new record for the company.  

Operating income for our E&P segment was $217 million for the third quarter, up from $172 million for the same period in 2009, as our strong production growth more than offset the impact of lower realized gas prices and increased operating costs and expenses. Our average realized gas price fell 8% to $4.67 per Mcf in the third quarter, compared to $5.06 for the same period last year. We currently have approximately 44 Bcf of our fourth quarter projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $6.26 per Mcf. This represents approximately 40% of our expected production during the quarter.

Our lease operating expenses per unit of production were $0.85 per Mcfe during the quarter, compared to $0.76 last year. The increase was primarily due to higher gathering and compressor fuel costs related to our Fayetteville Shale play.  

Our general and administrative expenses per unit of production declined to $0.28 per Mcfe in the third quarter, down from $0.38 last year, due to the impact of our increased production volumes.  

Taxes other than income taxes were $0.12 per Mcfe in the quarter, compared to $0.10 in the prior year.

Our full cost pool amortization rate continues to decline, dropping to $1.31 per Mcfe in the third quarter, from $1.43 in the prior year, primarily due to lower finding and development costs combined with the sale of certain East Texas oil and gas leases and wells in the second quarter of 2010.

Our total per unit operating cost and expenses (including LOE, G&A, taxes and full cost pool amortization rate) was $2.56 per Mcfe in the third quarter, down from $2.67 in the prior year period.

Operating income from our Midstream Services segment more than doubled in the third quarter to $53 million, compared to $25 million a year ago. The increase was primarily due to our increased gathering revenues, which were partially offset by increased operating costs and expenses. We currently forecast operating income for our Midstream Services segment of approximately $180 million and EBITDA of approximately $210 million for the year. At October 25th, our Midstream Services segment was gathering over 1.7 billion cubic feet of natural gas per day through 1,524 miles of gathering lines in the Fayetteville Shale play, compared to approximately 1.3 billion cubic feet per day a year ago. Included in our gathered volumes is approximately 190 million cubic feet per day of third-party gas.

To update you on the construction of the Fayetteville Express pipeline, we are very happy to report that interim service to Trunkline began earlier this month, and primary service will commence on or about December 1. Our initial firm capacity on the pipeline will be 400 million cubic feet per day on December 1, 2010, increasing to 1.2 Bcf per day by November 2011.

We invested approximately $1.5 billion in the first nine months of 2010, compared to $1.4 billion in the same period last year, and expect our capital investments for the year to be at or below our original capital budget of $2.1 billion. At September 30, we had $617 million borrowed on our $1 billion credit facility at an interest rate of less than 1% and had total debt outstanding of $1.3 billion. This currently leaves us with a debt to book capital ratio of 31%; however, we expect that to decline to about 28% by year-end.  

In summary, we had the best quarter in the company’s history. Our drilling and operating costs and expenses are continuing to decline. We are uniquely positioned to weather the current low gas price environment as one of the lowest cost operators in our industry with one of the strongest balance sheets.

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 financial measures to non-GAAP financial measures for the three months ended September 30, 2010 and September 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.

	3 Months Ended Sept. 30,
	2010	2009
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 406,009	$ 315,795
Add back (deduct):
Change in operating assets and liabilities	15,051	15,978
Net cash provided by operating activities before changes   in operating assets and liabilities	$ 421,060	$ 331,773