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Southwestern Energy (SWN)
Q4 2010 Earnings Call
February 25, 2011 10:00 am ET
Steven Mueller - Chief Executive Officer, President and Director
Greg Kerley - Chief Financial Officer, Executive Vice President and Director
Brian Singer - Goldman Sachs Group Inc.
Scott Hanold - RBC Capital Markets, LLC
Dan McSpirit - BMO Capital Markets U.S.
David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.
Gil Yang - BofA Merrill Lynch
Marshall Carver - Capital One Southcoast, Inc.
Jeffrey Hayden - Rodman & Renshaw, LLC
Scott Wilmoth - Simmons
Rehan Rashid - FBR Capital Markets & Co.
Previous Statements by SWN
» Southwestern Energ CEO Discusses Q3 2010 Results - Earnings Call Transcript
» Southwestern Energ Q2 2010 Earnings Call Transcript
» Southwestern Energ Q1 2010 Earnings Call Transcript
Thank you, and good morning, and thanks for joining us. With me today is 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, 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 materially differ.
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 our East Texas, 19 Bcf from Arkoma and 1 Bcf from Marcellus, which we kicked off late in the year. Our year-end proved reserves also increased by 35% to a record 4.9 Tcfe. It says in my notes here, approximately 100% of reserves are natural gas but I think I can say that essentially all of our reserves are natural gas. 55% were classified as proved developed in 2011, slightly higher than the 54% 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 as finding and development costs to $1.02 per Mcfe, including revisions. Our cost structure is one of the keys in this current price environment and our finding and development costs and production costs continue to be among the lowest in the industry.
Now, let's get into some more details. We'll start by talking about the Fayetteville Shale. The Fayetteville Shale continues to deliver exceptional results. Our 2010 drilling program at Fayetteville Shale added 1.6 Tcf of new reserves at finding and development costs of $0.86 per Mcf. This includes a net upward reserve revision of approximately 273 Bcf, due to improved well performance and positive revisions due to higher average gas prices. Our finding and development costs in Fayetteville Shale, excluding these revisions, was $1.04 per Mcf. Total proved net gas reserves booked in Fayetteville Shale at the end of the year 2010 were 4.3 Tcf, up 39% from reserves booked at the year end 2009. The average gross proved reserves in 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 three years of drilling inventory booked with our PUDs. We spud 658 wells in Fayetteville Shale during 2010 and placed a record 553 operated wells on production. We continue to prove 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 $2.9 million per well in 2009. The decrease in our drilling times and other savings and benefits from our vertical integration had more than offset longer average lateral lengths. Our average initial producing rates were approximately 3.4 million cubic foot per day, compared to last year's 3.5 million cubic foot per day average rate. During 2010, 40% of our operated wells were drilled on a perforated field as the first well in those sections, which created a slightly different mix of wells compared to our 2009 results. As for an update on our spacing test, at the year end 2010, we had drilled nearly all of our wells spacing test 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 are needed. As part of that process, we are also performing interference tests in certain of our closer spaced areas.
Switching to Pennsylvania, we invested approximately $118 million in Pennsylvania during 2010 and participated in 21 wells, of which six were completed and 15 were in progress at year end. These six are all operated horizontal Marcellus Shale wells located in our Greenzweig area in Bradford County. The production flows wells tested between four and eight million cubic foot per day and since then, we replaced three additional operated horizontal wells on production on February 18th, all of which are located in the Greenzweig area. Total daily gross operated productions in the area is currently 45 million cubic foot per day without compression. Flowing tubing pressures range from 1,100 to 1,300 pounds and choke sizes range from 23/64s to 40/64s. The wells are currently completed at average lateral lengths of approximately 4,500 feet and are averaging seven to 10 frac stages. We anticipate our Marcellus activity growth substantially in 2011, with 1 1/2 rigs running in 2011, compared to only one 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.