Southwestern Energy (SWN)
Q4 2011 Earnings Call
February 28, 2012 10:00 am ET
Steven L. Mueller - Chief Executive Officer, President and Director
Greg D. Kerley - Chief Financial Officer, Executive Vice President and Director
Scott Hanold - RBC Capital Markets, LLC, Research Division
Gil Yang - BofA Merrill Lynch, Research Division
Brian Singer - Goldman Sachs Group Inc., Research Division
Marshall H. Carver - Capital One Southcoast, Inc., Research Division
Joseph Patrick Magner - Macquarie Research
David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
David W. Kistler - Simmons & Company International, Research Division
Robert L. Christensen - Buckingham Research Group Incorporated
Dan McSpirit - BMO Capital Markets U.S.
Previous Statements by SWN
» Southwestern Energy's CEO Discusses Q3 2011 Results - Earnings Call Transcript
» Southwestern Energy's CEO Discusses Q2 2011 Results - Earnings Call Transcript
» Southwestern Energy's CEO Discusses Q1 2011 Results - Earnings Call Transcript
Greetings, and welcome to Southwestern Energy's Fourth Quarter Earnings Teleconference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, President and CEO. Thank you, sir. You may begin.
Steven L. Mueller
Good morning, and thank you for joining us. With me today are Greg Kerley, our Chief Financial Officer; 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 2011 results, you can find a copy on our website, www.swn.com.
Also, I'd like to point out that many of the comments during the 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 these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
Let's begin. 2011 was another record year for Southwestern Energy. We set new records in production reserves and as a result of our 24% production growth, we achieved the highest earnings and cash flow in our company's history. We produced 500 Bcfe, driven largely by our Fayetteville Shale play, where our production grew 25% to 437 Bcf. Our production from Marcellus Shale also grew from 1 Bcf in 2010 to 23 Bcf in 2011, while our Ark-La-Tex production declined from 54 Bcf in 2010 to 40 Bcf in 2011.
Our year-end proved reserves also increased by 19% to a record 5.9 trillion cubic feet of gas. Approximately 100% of our reserves were natural gas, and 45% were classified as proved undeveloped. We replaced 299% of our 2011 production at a finding and development cost of $1.31 per Mcfe, including revisions. This, along with our all-in cash cost of $1.27 per Mcfe, give us one of the lowest cost structures in the industry. The year -- this year has already started out to be a challenge, but as I tell our employees, our goal is not just to survive. It's to thrive.
Now to talk about our operating areas. In the Fayetteville Shale, we added 1.2 Tcf of new reserves at a finding and development cost of $1.13 per Mcf. Total proved reserves booked in the Fayetteville Shale play at year-end 2011 were 5.1 Tcf, up 17% from the reserves booked at the end of 2010. We spud 580 operated wells in the Fayetteville Shale during 2011 and placed a record 560 operated wells on production, resulting in a gross production from our operated wells to increase from 1.6 Bcf a day at the first of the year to 1.9 Bcf per day at the end of the year.
We saw continued improvement in our drilling practice in the Fayetteville Shale in 2011 as our operated horizontal wells are at an average completed well cost of $2.8 million per well, average horizontal length of 4,836 feet, and average time to drill of 8 days from re-entry to re-entry. This compared to approximately the same cost in 2010 with a shorter lateral. We also placed 73 wells on production during 2011 that were drilled in 5 days or less. In total, we have drilled 104 wells to date in 5 days or less.
It is amazing that it has taken 7 years since first production to transition the Fayetteville Shale drilling program from establishing first wells in this section to drilling multiple wells from a pad. Our average initial producing rates were approximately 3.3 million cubic foot per day compared to last year's 3.4 million cubic foot per day average rate. And in the fourth quarter of 2011, this average rate was over 3.6 million cubic foot of gas per day.
Now switching to Pennsylvania. We added 327 Bcf in new reserves at a finding and development cost of $1.02 per Mcf. Total proved reserves booked at our Marcellus Shale area at year-end 2011 was 342 Bcf, up from the 38 Bcf booked at the year-end 2010. As of year-end 2011, we had spud 70 wells, 23 of which were put on production and 67 of which were horizontals. Total daily production from the area was approximately 133 Mcf (sic) [MMcf] per day at December 31 and limited by high line pressures.
Our operator horizontal wells had an average completed well cost of $6.4 million per well, average horizontal lateral length of 4,007 feet and an average of 14 -- of 12 fracture stimulation stages. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 7.5 Bcf per well and approximately 8.6 Bcf per well for our proved developed wells in 2011.
As for new ventures, at December 31, 2011, we had 3.6 million net undeveloped acres, of which 2.5 million acres were located in New Brunswick, Canada, and the remaining approximately 1.1 million acres were located in the United States. In New Brunswick, we have invested approximately $24 million through December 31, 2011, and have acquired 248 miles of 2D seismic. In 2012, we intend to acquire approximately 130 additional miles of 2D, and our current plan includes drilling 2 stratigraphic well tests in the fourth quarter of 2012.
In our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana, we hold approximately 520,000 net acres at an average cost of $375 per acre. Earlier this month, we began flowing back our first well in the area, the Roberson 18-19 #1-15H, located in Columbia County, Arkansas. This well had a vertical depth of approximately 9,369 feet and horizontal lateral length of approximately 3,600 feet, and was completed in 11 stages. The lateral was landed in the lower 1/3 of the zone, and subsequent core analysis indicated this section had some of the lowest permeability in the entire interval. The well has been producing from 8 of the 11 stages, fracture stimulated. It has produced for 20 days of the originally planned 20- to 30-day cleanup period. Well production began on day 8, with the highest 24-hour rates to date of 103 barrels of oil per day, 200 Mcf per day of gas and 1,009 barrels of load water per day. 45% of load has been recovered to date.