Southwestern Energy (SWN) 8-K Southwestern Energy Third Quarter 2009 Earnings Teleconference

Southwestern Energy Third Quarter 2009 Earnings Teleconference

Speakers:

Harold Korell; Executive Chairman

Steve Mueller; President and Chief Executive Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell – Executive Chairman

Good morning, and thank you for joining us.  With me today are Steve Mueller, our Chief Executive Officer, and Greg Kerley, our Chief Financial Officer.

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 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.

Well, we had a solid quarter despite depressed natural gas prices which were at a seven-year low and the various curtailment issues we experienced related to maintenance and repairs of the Boardwalk Pipeline. We do not expect these factors to weigh as heavily in the fourth quarter of 2009, as the Boardwalk Pipeline was placed on-line sooner than we had expected and as gas prices appear to be moving higher than they have been over the past nine months. As a result of the Boardwalk Pipeline being back on-line, we were able to reach another milestone last week when we surpassed 1 Bcfe of net production per day as a company.

Meantime in other areas, things continue to heat up in Pennsylvania as joint ventures are being formed, companies drill and report high-rate wells and pay high prices in and around our acreage position.  Our plan is to begin an active drilling program there in 2010.  As we look ahead, we see continued profitable growth in our production and reserves which, coupled with our low cost structure, will create tremendous value for Southwestern Energy and its shareholders.

I will now turn the teleconference over to Steve for more details on our E&P and Midstream activities and then to Greg for an update on our financial results. Then we will be available for questions afterward.

Steve Mueller – President and Chief Executive Officer

Good morning.

During the 3rd quarter of 2009, we produced 73.2 Bcfe, up 38% from the 3rd quarter of 2008.  Our Fayetteville Shale production was 58.8 Bcf, 60% greater than the 37.2 Bcf we produced in the 3rd quarter of 2008.  Our remaining 3rd quarter production came from East Texas where we produced 9.0 Bcfe and 5.3 Bcf from our conventional Arkoma properties.  

As discussed last quarter, repairs and maintenance on the Texas Gas Transmission Pipeline (Boardwalk Pipeline) Fayetteville and Greenville laterals servicing our Fayetteville Shale caused us to experience curtailments that impacted our ability to transport our production.  Beginning on October 8th, the Fayetteville Lateral was placed back into service after being shut down since September 1st. The Greenville Lateral was also placed back into service in October after this shut down.  The completion of these repairs ahead of our anticipated schedule, as well as the continued strong performance of our Fayetteville Shale and East Texas wells, are the reasons for revising our previous gas and oil production guidance range for 2009 from 278 to 288 Bcfe to the new range of 297 to 300 Bcfe.  At this higher production guidance, we expect to have production growth of approximately 53% over 2008 levels.

In the first nine months of 2009, we invested approximately $1.2 billion in our exploration and production business activities and participated in drilling 476 wells.  Of this amount, approximately $1.0 billion, or 81%, was for drilling wells.  Additionally, we invested $167 million in our midstream segment, almost entirely in the Fayetteville Shale.

Fayetteville Shale Play

Speaking of the Fayetteville Shale, we invested approximately $1.0 billion in the first nine months of 2009 in this play including both our E&P and midstream activities.  At October 24th, our gross operated production rate was approximately 1.23 Bcf per day up from 600 MMcf per day a year ago.  We currently have 17 drilling rigs running in the Fayetteville, 13 that are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical portion of the wells.  

During the 3rd quarter, our horizontal wells had an average completed well cost of $2.9 million per well, average horizontal lateral length of 4,100 feet and average time to drill to total depth of 12 days from re-entry to re-entry. This compares to an average completed well cost of $2.9 million per well, average horizontal lateral length of 4,123 feet and average time to drill to total depth of 11 days from re-entry to re-entry in the 2nd quarter of 2009.  

Beginning in late 2008, we began drilling wells in the Fayetteville Shale to test tighter well spacing.  Through September 30th, we have placed over 200 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less.  Results to date have been encouraging.  The results from those currently drilled indicates between 10 and 12 wells per section in the Fayetteville Shale.  We will fine tune this analysis as well data is added over the next several months.  Additionally, we are testing eight different pilot areas with well spacings that will range from 300 to 600 feet apart.

During the 3rd quarter, we placed three wells on production with initial production rates over 6.0 MMcf per day.  Subsequent to the end of the 3rd quarter and through October 23rd, we placed two additional wells on production with initial production rates over 6.0 MMcf per day, including our highest rate well, the Linda Linn 08-12 1-23H located in Faulkner County, with an initial production rate of approximately 6.7 MMcf per day.

Haynesville

I’ll now move on to our Haynesville Shale activity where we are continuing to see encouraging results.  

The first horizontal well in our 50/50 joint venture targeting the Haynesville/Bossier Shale in Shelby and San Augustine Counties, Texas, the Red River 877 #1, reached total depth in the 4th quarter of 2008.  This well, which had a completed horizontal lateral of 2,718’, was production tested at a rate of 7.2 MMcfe per day in the 1st quarter of 2009. The second horizontal well, the Red River 164 #1, was drilled approximately 5 miles to the southeast and reached a total measured depth of 17,124’ with a 3,800’ horizontal lateral.  It was production tested at 13.4 MMcfe per day in the 2nd quarter.  We have completed a third well, the Red River 619 #1 well, located in San Augustine County, with a measured depth of 17,244’ with a 4,000’ horizontal lateral.  This well was production tested in the 3rd quarter at 16.7 MMcf per day.  Our fourth well, the Burrows Gas Unit #1-H is currently being tested.  A fifth well, the Red River 257 #1 is waiting on completion and, finally, we are currently drilling our sixth well, the Red River 257 #2, which is targeting the Middle Bossier, both located in San Augustine County.  Our total production from the Haynesville is currently approximately 34.7 MMcf per day gross, or 10.2 MMcf per day net.

Conventional Arkoma & East Texas

Finally, we participated in drilling 14 wells in the conventional Arkoma Basin and 33 wells in East Texas during the first nine months of 2009.  Twenty-eight of the East Texas wells were James Lime horizontal wells. Production from our Arkoma and East Texas properties was 16.9 and 24.6 Bcfe, respectively, for the first nine months of 2009, compared to 18.6 and 24.1 Bcfe for the first nine months of 2008.  We currently continue to have two operated rigs operating in East Texas and none in the Conventional Arkoma.

Summary

In summary, our E&P and Midstream businesses have had strong results in 2009 which we expect to continue into 2010.  As we prepare our capital budget for next year, we will continue to be focused on adding value in all of our areas including the Fayetteville, Haynesville, and Marcellus Shales.      

I will now turn it over to Greg Kerley who will discuss our financial results.

Greg Kerley – Executive Vice President and Chief Financial Officer

Thank you, Steve, and good morning. We had a solid third quarter despite depressed natural gas prices which declined during the quarter to their lowest level in seven years and the curtailment of a portion of our production due to maintenance and repairs of the Boardwalk Pipeline.

We reported net income of $118.3 million, or $0.34 per share, for the quarter, down from $218.2 million, or $0.63 per share, a year ago, primarily due to significantly lower natural gas prices. Our results in 2008 also included an after-tax gain on the sale of our utility assets of $35.4 million, or $0.10 per share. Despite the decline in our earnings, our cash flow from operations (before changes in operating assets and liabilities) was actually up 6% over the prior year to $331.8 million, as our production growth offset the effects of lower realized natural gas prices.  

Our average realized gas price during the third quarter was $5.06 per Mcf, which was approximately $3.50 per Mcf lower than our average realized price a year ago.  Our commodity hedge position increased our average realized gas price by $2.21 in the third quarter, and our average locational market differential was approximately $0.54 per Mcf.  

We currently have approximately 33 Bcf of our remaining 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.41 per Mcf.  We also have basis protected on approximately 50 Bcf of our expected fourth quarter gas production through hedging activities and sales arrangements at an average differential to NYMEX gas price of approximately $0.25 per Mcf, excluding fuel and transportation charges. Our detailed hedge position is included in our Form 10-Q that was filed yesterday.

Operating income for our E&P segment was $172.0 million in the third quarter of 2009, compared to $280.6 million in the third quarter of 2008.  The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses, which was partially offset by a 38% increase in our production volumes.  

Our total cash operating costs continue to be some of the lowest in the industry.  Our lease operating expenses per unit of production were $0.76 per Mcfe in the third quarter of 2009, compared to $0.96 for the same period in 2008.  The decrease primarily resulted from the impact that lower natural gas prices had on the cost of compressor fuel.

General and administrative expenses per unit of production were $0.38 per Mcfe in the third quarter of 2009, compared to $0.33 for the same period in 2008.  The increase was primarily due to higher payroll and other employee-related costs associated with the expansion of our operations, including a $5.4 million increase in incentive compensation that was accrued during the quarter, which were only partially offset by the effects of our increased production volumes.  For the year-to-date, our G&A expense has declined from $0.38 per Mcfe to $0.34 per Mcfe.

Taxes other than income taxes were $0.10 per Mcfe in the third quarter of 2009, down from $0.15 for the same period in 2008, primarily due to lower commodity prices.  

Our full cost pool amortization rate dropped to $1.43 per Mcfe in the third quarter, down from $1.86 in the prior year.  The decline was primarily due to the non-cash ceiling test impairment we recorded in the first quarter of 2009.

Operating income from our Midstream Services segment was $25.1 million in the third quarter of 2009, up from $18.3 million for the same period in 2008.  The increase was primarily due to higher gathering revenues resulting from the significant increase in our gathered volumes in the Fayetteville Shale, partially offset by increased operating costs and expenses.  

We invested approximately $1.4 billion during the first nine months of 2009, compared to $1.3 billion for the same period in 2008, and continue to expect that our total capital investments for the year will be approximately $1.8 billion.

We have a strong balance sheet with significant liquidity and financial flexibility.  As of September 30th, we had $285 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.1%.  For the quarter, our debt outstanding increased by $89 million resulting in total debt outstanding of approximately $960 million at September 30th and we had a debt to book capital ratio of 30%.  Our debt-to-market capitalization ratio was only 6%.  

We believe that our focus on return on investment and our low cost structure combined with our large drilling inventory uniquely positions us to create significant value for our shareholders over the next few years. 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 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, 2009 and 2008.  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 September 30,
	2009	2008
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$     315,795	$     378,455
Add back (deduct):
Change in operating assets and liabilities	15,978	(66,316)
Net cash provided by operating activities before changes   in operating assets and liabilities	$     331,773	$     312,139