Southwestern Energy (SWN) 8-K Southwestern Energy Second Quarter 2012 Earnings Teleconference

Southwestern Energy Second Quarter 2012 Earnings Teleconference

Speakers:

Steve Mueller; President and Chief Executive Officer

Bill Way, Executive Vice President and Chief Operating 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 Bill Way, our Chief Operating Officer, Greg Kerley, our Chief Financial Officer, Jeff Sherrick, Senior VP of Corporate Development, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday’s press release regarding our second quarter 2012 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.

Now let’s begin.  Bill and Greg will talk about SWN’s second quarter performance and will compare several important numbers.  I want to take just a minute and talk about the one number that was foremost in our minds – the average second quarter NYMEX price of $2.22 per mcf.  That is a 26% reduction from year-end 2011!  The swift and rapid decrease in gas price has caused a 49% year over year decrease in total industry rigs drilling for gas in the US. SWN is also rapidly adjusting to the price changes but rather than retrenching like the rig count our emphasis on Value+ allowed us to continue our strong progress in every investment area in the second quarter.  As we mentioned last quarter, investing in the best wells in the Fayetteville Shale has increased the initial production rates and more importantly, the quality of the completed wells.  In addition, we continued to decrease days to drill below our recent year-end 2011 estimates.  The Marcellus production is ramping up and we are encouraged about what we are seeing in our New Ventures projects.  Record production, faster times and lower costs are a product of a culture that is focused on Value+.  I will now turn the call over to Bill for more details on the results of that focus in the second quarter.   

Bill Way, Executive Vice President and Chief Operating Officer

Fayetteville Shale Play

Thank you Steve and good morning everyone. In the Fayetteville Shale, we placed 131 operated wells on production in the second quarter, resulting in net production of 121 Bcf, up from 116 Bcf in the first quarter and 107 Bcf a year ago, which was a new quarterly record for us. Our operated horizontal wells had an average initial production rate of 3.5 million cubic feet of gas per day, up from 3.3 million cubic feet of gas per day in the first quarter, an average completed well cost of $2.8 million per well and an average drilling time of 6.9 days during the quarter, which is the fastest quarterly drill time in the history of the play. We also placed 30 wells on production during the quarter that were drilled in 5 days or less. As

you may recall, we have optimized our portfolio in the Fayetteville and are targeting the highest-return wells in the field. Going forward, we expect to see our average production on a per well basis improve over the next few quarters.

On the midstream side, our gas gathering business in the Fayetteville Shale continued its strong performance and at June 30th was gathering approximately 2.1 billion cubic feet of natural gas per day through 1,829 miles of gathering lines, compared to gathering approximately 2.0 billion cubic feet per day a year ago. Lately, our production in the Fayetteville has been affected by the recent extremely high temperatures in central Arkansas and, year-to-date, we estimate that production from the field has been impacted by almost 1.0 Bcf due to the extreme heat. Since June 30, however, our gross production rate has returned to approximately 2 Bcf per day, however we still continue to manage the effects of the heat on our compressors and dehydration facilities.

Marcellus Shale

In Bradford and Susquehanna Counties in Pennsylvania, we had 41 operated Marcellus Shale wells on production at the end of the quarter resulting in net production of 9.9 Bcf, which is up from 5.1 Bcf in the same quarter in 2011. Gross operated production was approximately 166 million cubic feet of gas per day at June 30. Since that time, our gross production rate from the area has surpassed 200 million cubic feet of gas per day.

Our operations at Greenzweig continue to go very well, with 39 producing wells on line. We also just placed additional compression on line at Greenzweig which already allowed us to increase our rate from the area.

We began selling gas from our Price area in Susquehanna County in May and we had 2 wells producing at a combined rate of 10 million cubic feet of gas per day at June 30 without the aid of compression into TGP 300.

In our Range Trust area, which is approximately 70,000 net acres in Susquehanna County, we have completed and flow tested 3 wells to date before they were shut-in waiting on pipelines. The wells were only flowed for a short time period to avoid flaring of gas and showed strong performance in the initial 5-day flowback period. Productivity calculations for all three wells indicate that Greenzweig-type performance should be expected once the wells are turned to sales in the fourth quarter.

New Ventures

In New Ventures, we hold approximately 3.7 million net undeveloped acres, of which 2.5 million net acres are located in New Brunswick, Canada.

In our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana, we have over 560,000 net acres leased, we have drilled four wells in the play to date and we are currently drilling two additional wells. Our first two wells were completed earlier this year and are currently shut-in for testing. Our third well, the BML located in Union Parish, Louisiana, was drilled to a vertical depth of approximately 10,400 feet with a 4,300-foot horizontal lateral and was completed with 19 successful fracture stimulation stages in June. After 41 days of flowing up casing and after approximately 43% of the load recovered, this well’s highest 24-hour producing rate to date was 421 barrels of 50^o API oil per day, 3.9 million cubic feet of gas per day and 836 barrels of water per day with a calculated flowing bottom hole pressure of 5,700 psi on a 24/64-inch choke. The BML well also averaged 353 barrels of oil per day and 3.3 million cubic feet of gas per day for more than 30 days during the test period.

We have installed tubing and we have shut the well in order to perform a pressure build-up test and wait on pipeline connections. Once pipeline connections can be completed, we expect to begin selling both oil

and gas from the well in the fourth quarter of 2012. The oil pricing we are receiving from this area is at a premium to WTI and analysis of the gas shows a high Btu content of around 1,220, so we would receive a premium to Nymex due to the richer gas liquids. We are encouraged by the BML’s results, however we also know that we have more to learn in order to make the play economic.

Our fourth well, the Johnson located in Union Parish, Louisiana, was drilled to a vertical depth of 10,507 feet in July. Like the BML well, this well also encountered unusually high pressure within the target formation. We will complete this well vertically in order to test the effects of fracturing fluid and sand type on reservoir performance, however it will be able to be re-entered as a horizontal well in the future. We also commenced drilling on the Dean well located in Union Parish, Louisiana, which is currently drilling at approximately 8,325 feet. This well is planned to be drilled to approximately 10,450 feet and be completed vertically. Finally, we are also drilling the Doles well located in Union Parish, Louisiana, which is currently drilling at approximately 6,375 feet to a planned measured depth of approximately 17,300 feet with a 6,000-foot horizontal lateral.

In our Denver-Julesburg Basin oil play in eastern Colorado we have leased approximately 290,000 net acres and completed our first well in July, the Ewertz Farms located in Adams County. This well was drilled to a total vertical depth of 8,550 feet with a 2,000-foot horizontal lateral targeting the Marmaton formation. We are in the early days on this well with less than a quarter of flowback having been recovered, but we are encouraged as oil production began on Day 3 after flowback commenced. The highest 24-hour producing rate to date for the Ewertz Farms well was 65 barrels of oil per day on a pump, 40 Mcf of gas per day and 740 barrels of water per day. We have also drilled the Staner 5-58 #1-8 well located 20 miles away in Arapahoe County to a total vertical depth of 9,650 feet. This well is planned to be completed in August as a vertical completion. We will evaluate the production from these two wells over the next 90 days and additional drilling in the area is planned near the end of the year.

In New Brunswick, we have deferred our planned 2012 exploration program until 2013 to provide additional time for public engagement and completion of the permitting process. The Department of Natural Resources and other key government officials support this decision and we will continue to work together with the appropriate parties to be able to accomplish the work we would like to do in 2013.

Finally, we spud our Bedwell horizontal well in Sheridan County, Montana on July 10 targeting the Bakken/Three Forks objectives. This well drilled through the objective section and reached a total vertical depth of 8,619 feet. We are currently drilling the curve at approximately 7,600 feet TVD with a planned 3,200-foot horizontal lateral. At this time, this is all we are going to say about this area.

In closing, we continue to do the Right Things – which is focusing on PVI, driving down our costs and continuing the innovation process across all our existing assets and new plays. We also are encouraged about our New Venture ideas and have additional exciting ideas that will come to the surface at a later date. I look forward to reporting back to you next quarter on our progress. 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, Bill, and good morning.  We reported earnings for the second quarter of approximately $91 million, or $0.26 per share, excluding the non-cash ceiling test impairment of the company’s natural gas and oil properties which resulted from low gas prices.

Our discretionary cash flow was $355 million in the second quarter and $725 million for the first six months.  Despite significantly lower natural gas prices our year-to-date discretionary cash flow is down

only 14%, due to our production growth, strong commodity hedge position and performance of our Midstream business and our low cost structure.

Our average realized gas price of $3.12 per Mcf for the quarter, was down 27% from the same period last year, while Nymex settlement prices for the second quarter were approximately half of what they were a year ago.  Our realized gas price included gains from our commodity hedging activities which increased our average gas price by $1.36 per Mcf during the quarter.  For the remainder of 2012 we have 134 Bcf of our gas production hedged at a weighted average floor price of $5.16 per Mcf.  This strong commodity hedge position, along with the cash flow generated by our Midstream Services business protects approximately 60% of our expected cash flow for 2012.

Operating income for our E&P segment was $76 million during the quarter, excluding the non-cash impairment, compared to $222 million in the same period last year.  

Our cost structure continues to be one of the key drivers of our financial results and is one of the lowest in the industry, with all-in cash operating costs of $1.20 per Mcfe for the second quarter which includes our LOE, TOTI, G&A and interest.  

Operating income from our Midstream Services segment grew by 20% in the second quarter to approximately $72 million.  The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays.  

Our balance sheet continues to be in good shape with a net debt to book capital ratio of a little less than 30% and a total debt to EBITDA ratio of about 1.0.  We currently have nothing drawn on our unsecured $1.5 billion credit facility and also had cash at the end of the quarter of around $41 million and restricted cash from the sale of our Overton properties of approximately $144 million, which further strengthens our liquidity position.  

Year to date, we have invested $1.2 billion, including $1.1 billion in our E&P business.  Our planned total capital investment program for 2012 remains at $2.1 billion and was front-end loaded in the first two quarters by design, so we expect a decline in our capital investing during the third and fourth quarters of the year and as a result we expect to end the year with no additional increase in our total debt level from where we are today and  also expect to hit our production targets.  

Looking ahead, we are focused on keeping our balance sheet in good shape and will remain vigilant in reducing our costs even further and remain flexible in our decisions on capital investments.  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 March 31, 2012.  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 EndedJune 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (488,100)	$ 167,454
Add back:
Impairment of natural gas and oil properties (net of taxes)	578,879	--
Net income, excluding impairment of natural gas and oil properties	$ 90,779	$ 167,454

	3 Months EndedJune 30,
	2012	2011
Diluted earnings per share:
Net income (loss) per share	$ (1.40)	$ 0.48
Add back:
Impairment of natural gas and oil properties (net of taxes)	1.66	--
Net income per share, excluding impairment of natural gas and oil properties	$ 0.26	$ 0.48

	3 Months EndedJune 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 392,727	$ 460,451
Add back (deduct):
Change in operating assets and liabilities	(38,200)	(12,237)
Net cash provided by operating activities before changes  in operating assets and liabilities	$ 354,527	$ 448,214

	6 Months EndedJune 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 837,390	$ 856,930
Add back (deduct):
Change in operating assets and liabilities	(112,043)	(17,184)
Net cash provided by operating activities before changes  in operating assets and liabilities	$ 725,347	$ 839,746

	3 Months EndedJune 30,
	2012	2011
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ (859,872)	$ 222,539
Add back:
Impairment of natural gas and oil properties	935,899	--
E&P segment operating income excluding impairment  of natural gas and oil properties	$ 76,027	$ 222,539

Net Debt Reconciliation
(in thousands)
	June 30, 2012
Total Debt	$      1,670,011
Stockholder’s Equity	3,515,877
Total Capitalization	$     5,185,888
Total Debt	$      1,670,011
Less: Cash and Cash Equivalents	(41,499)
Less: Restricted Cash	(144,384)
Net Debt	$      1,484,128
Net Debt	$      1,484,128
Stockholder’s Equity	3,515,877
Total Adjusted Capitalization	$      5,000,005
Total Debt to Total Capitalization Ratio	32.2%
Less: Impact of Cash, Cash Equivalents and
Restricted Cash	(2.5%)
Net Debt to Adjusted Capitalization Ratio	29.7%