Southwestern Energy Fourth Quarter and Full-Year 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 fourth quarter and full-year 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, 2009 was an exceptional year for Southwestern Energy. We saw several milestones this year, including setting new records for production, reserves, reserve replacement and cash flow, all in a year where we saw natural gas prices which were at a seven-year low and all the problems we encountered with the Boardwalk Pipeline. We celebrated our 5-year anniversary in the Fayetteville Shale play this year while also reaching a production milestone of 1 Bcf per day from the play. We drilled and completed our 1,000th well in the Fayetteville Shale, on our way to completing many more in the years to come. Finally, we continued to have an industry-leading low cost structure, as our finding and development cost of $0.86 per Mcfe and lease operating expense of $0.77 per Mcfe in 2009 are among the lowest in our industry. This is all pretty amazing when you consider that it was just five years ago when we set all of this in motion with the discovery of the Fayetteville Shale play.

Meantime in our other areas, things are continuing to go well in our East Texas James Lime and Haynesville activities and in Pennsylvania, where we have just started an active drilling program there. 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.  As Harold stated, we had an outstanding year in 2009 and our operational metrics are some of the best in the industry.  Our production grew by 54% to a record 300 Bcfe, primarily as a result of the growth from our Fayetteville Shale Play where our production grew 81% to 243 Bcf.  We also produced 34.9 Bcfe from East Texas and 22.0 Bcf from the Arkoma Basin.

Our year-end proved reserves increased by 67% to a record 3.7 Tcfe.  Approximately 100% of our reserves were natural gas and 54% were classified as proved developed, down 8% from 62% in 2008.  We are also one of the few companies that have recorded net positive reserve revisions, as the improving performance from our Fayetteville Shale wells more than offset negative price revisions due to low gas prices and some performance revisions in our East Texas and Arkoma Basin programs.

For the last three years, our reserve replacement has averaged over 500% of our annual production.  We replaced 592% of our 2009 production at a finding and development cost of $0.86 per Mcfe, including revisions.  Excluding revisions, we replaced 561% of our 2009 production at a finding and development cost was $0.91 per Mcfe.  

Fayetteville Shale Play

Now, to talk a bit about our operating areas.  The Fayetteville Shale continues to deliver exceptional results.  We invested approximately $1.3 billion in our Fayetteville Shale drilling program during 2009, adding 1.8 Tcf of new reserves at a finding and development cost of $0.69 per Mcf.  This includes net upward reserve revisions of approximately 238 Bcf, as our improved well performance more than offset negative revisions due to lower gas prices.  The finding and development cost excluding these revisions was $0.80 per Mcf.  

Total proved net gas reserves booked in the Fayetteville Shale play at year-end 2009 were 3.1 Tcf, more than double the reserves booked at the end of 2008.  The average gross proved reserves for the undeveloped wells included in our year-end 2009 reserves was approximately 2.2 Bcf per well, up from 1.9 Bcf per well at year-end of 2008, and based upon our current drilling pace, we have approximately two years of drilling inventory booked as PUDs.

During 2009, we continued to improve our drilling and completion practices in the Fayetteville Shale play.  Our horizontal wells had an average completed well cost of $2.9 million per well, compared to an average of $3.0 million per well in 2008, as the decrease in our drilling times and other savings more than offset a 13% increase in average lateral length.  Our initial producing rates improved 25% over last year, as wells placed on production during 2009 averaged initial production rates of approximately 3.5 MMcf per day, compared to average initial production rates of 2.8 MMcf per day in 2008.  

Mid-year 2009, we celebrated reaching 1 Bcf per day from the Fayetteville, as gross production from our operated wells climbed from approximately 720 MMcf per day at the beginning of 2009 to approximately 1.2 Bcf per day at year-end.  Recently, we have had some delays due to operational issues and the colder weather that have caused 25 fewer wells to be put on production during the last few months than originally planned.  As a result, we have added 2 additional drilling rigs to help us catch up to our projected wellcount which we expect will happen sometime in the third quarter.  We currently are running 22 drilling rigs in the Fayetteville Shale play area, 16 that are capable of drilling horizontal wells and 6 smaller rigs that are used to drill the vertical section of the wells.  

East Texas Field

In our East Texas operating areas we had excellent results, posting production growth of 10% to 34.9 Bcfe with reserves of approximately 330 Bcfe at year-end.  In 2009, we invested approximately $167 million and participated in 46 wells in East Texas, of which 33 were successful and 13 were in progress at year-end, resulting in a 100% success rate.  

We continued to have good success in our James Lime carbonate play and through December 31, 2009, had participated in a total of 77 horizontal wells.  Of those, 43 were operated by us and placed on production at an average gross initial production rate of 9.8 MMcfe per day.  

We also kicked off our drilling program targeting the Haynesville and Middle Bossier Shale intervals in Shelby and San Augustine Counties in 2009 with very good results.  After our first horizontal well production tested at 7.2 MMcf per day in the first quarter of 2009, we have drilled four additional wells in the Haynesville Shale formation which production tested at 13.4, 16.7, 21.0 and 18.1 MMcf per day, respectively.  Additionally, we completed our first well in the Middle Bossier formation which production tested at 11.3 MMcf per day.  

We are currently completing our sixth Haynesville well, the Red River 620 #1-H, and drilling two additional Haynesville wells in the area, the Red River 619-2 #1H and the Owens #1H, both of which should be completed sometime in the second quarter.  In total, we have approximately 42,300 net acres we believe are prospective for the Haynesville and Middle Bossier Shales and our average gross working interest is approximately 61%.  

In addition to the James Lime, Haynesville and Middle Bossier targets, we have placed our first Pettet oil well on production.  The Acheron #2H well was placed on production in January and had initial production rates of 465 barrels of oil per day plus 2.5 MMcf of gas per day.  We are currently participating in two Pettet wells which are being completed.

Conventional Arkoma

In our conventional Arkoma Basin program, we had approximately 208 Bcf of reserves at year-end 2009 and produced 22.0 Bcf, compared to 24.4 Bcf in 2008.  Our production decreased during 2009 primarily due to significantly lower capital investments in the area as compared to 2008 levels.  In 2009, we invested approximately $40 million in our conventional Arkoma drilling program and participated in 20 wells, of which 15 were successful and 3 were in progress at year-end, resulting in an 88% success rate.

Appalachia

At December 31, 2009, we had approximately 149,000 net acres in Pennsylvania prospective for the Marcellus Shale.  Our undeveloped acreage position as of December 31, 2009 had an average remaining lease term of 5 years, an average royalty interest of 13% and was obtained at an average cost of approximately $594 per acre.  During 2009, we invested approximately $40 million in Pennsylvania, almost all of which was for acquisition of acreage, including approximately 22,829 net acres in Lycoming County that was purchased for approximately $8.7 million, or $382 per acre.

We are currently drilling our first horizontal well since 2008 in Pennsylvania.  The Heckman Camp #1 well is located in Bradford County, and first gas production is expected from the area late in the 2nd quarter of 2010.

Summary

In summary, we are very pleased with our results in 2009 and our planned capital investment plan for 2010 continues to build on that success.  While we are very proud of our accomplishments in 2009 and over the past five years, we also know that we have much more work to do.  We know that our disciplined approach to capital investing, focus on organic growth and financial flexibility will keep us extremely well-positioned during both the good and the challenging times.  We are looking forward to what lies ahead in 2010 and in the years to come.  

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 an exceptional year in 2009, both operationally and financially, despite natural gas prices falling to their lowest levels in 7 years.

For the calendar year, we reported net income of $523 million, or $1.52 per share, excluding a $558 million after-tax ceiling test impairment of our oil and gas properties during the first quarter of 2009.  Cash flow from operations (before changes in operating assets and liabilities) was up 23% to $1.4 billion as our production growth more than offset the effect of significantly lower natural gas prices.

For the 4th quarter, we reported earnings of $158 million, or $0.45 per share, a 51% increase over the prior year period, as the significant growth in our production volumes more than offset the decline in our average realized gas price.  Our production totaled 89 Bcfe in the fourth quarter, up 55% from the prior year period, and we realized an average gas price of $5.29 per Mcf down from $5.93 in 2008.  Our commodity hedge position increased our average realized gas price by approximately $1.50 per Mcf in the 4th quarter.  

We currently have 66 Bcf, or approximately 16%, of our 2010 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.02 per Mcf.  Our detailed hedge position is included in our Form 10-K filed yesterday.

Operating income for our E&P segment (excluding the non-cash ceiling test impairment) was $750 million in 2009, compared to $814 million in 2008.  For the year, we grew our production by 54% to 300 Bcfe and realized an average gas price of $5.30 per Mcf, which was down approximately 30% from the prior year.  

We continue to have one of the lowest cost structures in our industry, with a full-cycle cash cost of approximately $2.14 per Mcf in 2009, and a 3-year average of $2.75 per Mcf.  This includes our F&D costs, lease operating costs, taxes, G&A and interest expense.  

As Steve noted, our finding and development cost was $0.86 per Mcf in 2009, including revisions, down from $1.53 in 2008.

Our lease operating expenses per unit of production were $0.77 per Mcfe in 2009, down from $0.89 in 2008.  The decrease in our operating costs was primarily due to the impact that lower natural gas prices had on the cost of compressor fuel during 2009.  

Our general and administrative expenses per unit of production declined to $0.35 per Mcfe in 2009, down from $0.41 in 2008.  The decrease was primarily due to the effects of our increased production volumes which more than offset the effects of increased payroll, incentive compensation and other employee-related costs primarily associated with the expansion of our operations in the Fayetteville Shale play.  We added a total of 335 new employees during 2009.  

Taxes other than income taxes were $0.11 per Mcfe in 2009, down from $0.13 in the prior year, due to lower commodity prices and the change in the mix of our production volumes.  

Our full cost pool amortization rate also declined, dropping to $1.51 per Mcfe in 2009, from $1.99 in the prior year.  The decline was due to a combination of the ceiling test impairment recorded in the first quarter of 2009, our lower finding and development costs and the sale of natural gas and oil properties in 2008.

Operating income from our Midstream Services segment doubled in 2009 to $123 million.  The increase was primarily due to increased gathering revenues related to production growth in the Fayetteville Shale play, partially offset by increased operating costs and expenses.  At December 31, 2009, our Midstream segment was gathering approximately 1.3 billion cubic feet of natural gas per day through 1,137 miles of gathering lines in the Fayetteville Shale play, compared to gathering 802 million cubic feet per day a year ago.  

We invested $1.8 billion during 2009, approximately equal to our investments in 2008.  We expect that our total capital investments for 2010 will be approximately $2.1 billion.  There is clearly uncertainty today regarding natural gas prices, so our capital plans will remain flexible.  If we see a repeat of the low gas prices we saw in 2009, we will actively manage our capital program and make reductions in our 2010 plans.  However, if gas prices rebound during the year, we could increase our planned investments and accelerate the development of our Fayetteville Shale play by adding additional drilling rigs.

We have a strong balance sheet with significant liquidity and financial flexibility.  At year-end, we had $325 million borrowed on our $1 billion revolving credit facility at an average interest rate of 1.1%, and had total debt outstanding of a little less than $1 billion.  This leaves us with a debt to book capital ratio of 30% and a debt to market capitalization ratio of only 6%.  

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.

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the twelve months ended December 31, 2009 and December 31, 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.

	12 Months Ended Dec. 31,
	2009	2008
	(in thousands)
Net income (loss) attributable to Southwestern Energy:
Net income (loss) attributable to Southwestern Energy	$ (35,650)	$ 567,946
Add back:
Impairment of natural gas and oil properties (net of taxes)	558,305	--
Net income attributable to Southwestern Energy,   excluding impairment of natural gas and oil properties	$ 522,655	$ 567,946

	12 Months Ended Dec. 31,
	2009	2008
Diluted earnings per share:
Net income (loss) per share attributable to   Southwestern Energy stockholders	$ (0.10)	$ 1.64
Add back:
Impairment of natural gas and oil properties (net of taxes)	1.62	--
Net income per share attributable to Southwestern Energy stockholders,   excluding impairment of natural gas and oil properties	$ 1.52	$ 1.64

	12 Months Ended Dec. 31,
	2009	2008
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 1,359,376	$ 1,160,809
Add back (deduct):
Change in operating assets and liabilities	81,652	6,685
Net cash provided by operating activities before changes   in operating assets and liabilities	$ 1,441,028	$ 1,167,494

	12 Months Ended Dec. 31,
	2009	2008
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ (157,725)	$ 813,504
Add back:
Impairment of natural gas and oil properties	907,812	--
E&P segment operating income, excluding impairment   of natural gas and oil properties	$ 750,087	$ 813,504

Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following computes F&D costs using information required by GAAP for the periods ending December 31, 2009 and December 31, 2008, and three years ending December 31, 2009.

	For the 12 Months Ending December 31, 2009	For the 12 Months Ending December 31, 2008	For the 3 Years Ending December 31, 2009	Fayetteville Shale Play 2009	Fayetteville Shale Play 2008
Total exploration, development and acquisition costs incurred ($ in thousands)	$ 1,529,876	$ 1,559,995	$ 4,460,747	$ 1,259,151	$ 1,191,558
Reserve extensions, discoveries and acquisitions (MMcfe)	1,685,191	920,181	3,113,227	1,576,980	824,706
Finding & development costs, excluding revisions ($/Mcfe)	$ 0.91	$ 1.70	$ 1.43	$ 0.80	$ 1.44
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)	1,778,045	1,018,281	3,335,156	1,814,665	983,635
Finding & development costs, including revisions ($/Mcfe)	$ 0.86	$ 1.53	$ 1.34	$ 0.69	$ 1.21

The company believes that providing a measure of F&D costs is useful for investors as a means of evaluating a company’s cost to add proved reserves, on a per thousand cubic feet of natural gas equivalent basis. These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Southwestern’s financial statements prepared in accordance with GAAP (including the notes thereto). Due to various factors, including timing differences and the SEC’s 2009 adoption of a number of revisions to its oil and gas reporting disclosure requirements, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded and development costs, including future development costs for proved undeveloped reserve additions, may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in Southwestern’s filings with the SEC, future F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern’s F&D costs may not be comparable to similar measures provided by other companies.