Southwestern Energy Second Quarter 2006 Earnings Teleconference

Speakers:

Harold Korell; President, Chairman and Chief Executive Officer

Richard Lane; Executive Vice President and President of the company’s Exploration and Production business

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell: Good morning, and thank you for joining us.  With me today are Richard Lane, the President of our Exploration and Production segment and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of the press release we announced yesterday regarding our second quarter 2006 financial results, you can call Annie at (281) 618-4784 and she’ll fax a copy to you.  Also, I would like to point out that many of the comments during this teleconference may be regarded as forward-looking statements that involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings.  These forward-looking statements are subject to risks and uncertainties, many of which are beyond our control.  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.

During the second quarter, our development drilling programs in East Texas and the Arkoma Basin continued to deliver solid results, and we made significant progress in our Fayetteville Shale play.  We increased the pace of our drilling in the Fayetteville Shale as additional rigs were placed in service, and we saw marked improvement in well performance resulting from improvements in our fracture stimulation practices.  As a result, our production volumes from the Fayetteville Shale have started to increase dramatically, with gross production from the play at approximately 50 million cubic feet of gas per day, up from about 20 million cubic feet of gas per day in early May.  

At this time, we have 10 rigs running in the Fayetteville Shale play, including 5 of our company-owned rigs which are performing very well.  We expect 3 more rigs to be delivered in August, with a total of 19 to 20 rigs to be drilling in the play by year-end.  We currently expect to spud 175 to 200 wells in 2006 as we accelerate development and assess un-drilled areas of the play.  Richard will give a full update on our E&P operations in a moment.  

On the financial side, we again set new quarterly records for net income and cash flow, primarily due to higher production and higher realized commodity prices.  As mentioned in our release, we also saw increases in our per unit costs and expense reflecting the significant “up-front” investment we have made in equipment and personnel related to our Fayetteville Shale play.  

I’d like to now turn the teleconference over to Richard Lane, who will tell you more about our E&P activities, then to Greg Kerley to discuss our financial results.

Richard Lane: Thank you and good morning.

Our total production for the 2nd quarter was 16.4 Bcfe, up 9% from the 15.0 we produced in the 2nd quarter of 2005 and up 11% for the first six months over 2005.  Our Fayetteville Shale production alone was 1.8 Bcfe in the 2nd quarter, up substantially from the 0.7 Bcfe we produced in the 1st quarter.  

Through the 2nd quarter, we have spudded a total of 170 wells, including 86 wells in our Fayetteville Shale play, 43 wells in East Texas, 34 wells in the conventional Arkoma Basin, six wells in the Permian Basin and one in the Rockies.  We invested a total of $344.2 million in our E&P program during the 1st half of 2006.  We currently have 20 rigs running, 10 rigs in the Fayetteville Shale play, 5 rigs in East Texas, 3 rigs in the conventional Arkoma Basin, and 2 in the Permian Basin.  

Fayetteville Shale Play

In the first six months of 2006, we invested approximately $119.7 million, including $88.6 million for drilling and completions and $17.0 million for leasehold.  As of July 31, 2006, we have now drilled and completed 105 wells, including 51 vertical wells and 54 horizontal wells.  Twenty-nine of our most recent horizontal wells have been completed with either slick water or cross-link fracture treatments, as we have moved away from earlier nitrogen foam completions.  The average initial production test rate for these 29 wells was 1.7 MMcf per day, 20 of which have been on production for more than one month.  The average rate for these 20 wells after 30 days was 1.6 MMcf per day.

In yesterday’s earnings release, we included an update of the horizontal well production graph for wells which were stimulated using a slickwater or cross-link frac.  This graph continues to show improved early production performance from these wells over earlier completions.  

We also included a graph of gross production volumes from our Fayetteville Shale Play which shows the effect of improved well performance and project acceleration.  Current total gross production from our Southwestern-operated wells is approximately 50 MMcf per day, up from 20 MMcf per day at May 1st.  We expect our gross 2006 exit rate to be near 100 MMcf per day.

Here are a few recent well examples.  In our Cove Creek Field, located in Faulkner and Van Buren Counties, the Edwards #2-36-H well had an initial production test of 1.7 MMcf per day and is currently producing 1.5 MMcf per day after being on production for 93 days.

In our Scotland Field, located in Van Buren County, the Black #1-21-H well initially production tested at 2.0 MMcf per day and is currently producing 1.5 MMcf per day after being on production for 107 days.

Our Gravel Hill Field, in Van Buren and Conway Counties, is currently producing approximately 28 MMcf per day.  We are expanding our gas gathering capacity in the Gravel Hill and Scotland Field areas.  As a result of the higher production rates from newer wells, increased gathering line pressure is temporarily restricting production from some older wells in the areas.  A few Gravel Hill wells of note are the Anadarko #1-11-H, the Evans #1-32-H, the Grills #2-31-H,  the Guinn #2-6-H, and the Russell #1-33-H.  These wells are currently producing at an average rate of 2.4 MMcf per day after being on production for an average of 47 days.  The Anadarko #1-11-H tested at 3.6 MMcf per day and is still producing 2.7 MMcf per day after being on-line for 80 days.

As of July 31st, we held a total of approximately 883,000 net acres in the Fayetteville Shale Play area.  Of this, approximately 758,000 net acres were in the undeveloped play area and the remaining 125,000 net acres were in the traditional “Fairway” area of the Arkoma Basin that is held by conventional production.

In the 2nd quarter, we extended the play approximately 20 miles to the east with the drilling of the Hefly #1-12-H located in our Sharkey pilot area of White County.  The Hefly well was drilled and logged approximately 363 feet of gross Fayetteville Shale with pay comparable to what we are seeing in our Cove Creek field.  We are also currently drilling the horizontal lateral sections in our first wells in the Caddis pilot area east of Cove Creek and the Goblin pilot area northwest of Sharkey.  By the end of 2006, we expect to have effectively tested a substantial portion of our Fayetteville Shale acreage.

As mentioned previously, we currently have 10 rigs running in our Fayetteville Shale Play.  Of these 10, two are “shallow” rigs which we use to drill the vertical portion of our wells prior to moving in one of the larger rigs capable of drilling the horizontal section.  Five of these are company-owned built-for-purpose rigs.  We expect to have 3 or 4 shallow rigs and up to 16 deeper rigs in the play at the end of this year.  

We are very pleased with the progress we have made in the Play to date and look forward to additional improvements throughout the year.

Arkoma Basin Conventional

In our conventional Arkoma Basin properties, we invested approximately $39.5 million and spudded 34 wells in the 1st six months of 2006.

We currently have three rigs running in the conventional Arkoma Basin.  All of these rigs are drilling at our Ranger Anticline Project Area in Yell and Logan Counties, Arkansas.  One 2nd quarter well of note in the Ranger Anticline Area is the SKK #1-13.  This well, located between our main producing area and the eastern extension we started developing in 2005, is presently producing 2.3 MMcf per day after being on production for 60 days.  We are currently completing an offset to the Smith #1-12 which had good gas shows in the Basham, Nichols, Turner, and Borum sands while drilling.  We anticipate that we will have up to five rigs drilling at Ranger later this year and drill between 45 and 55 wells in 2006.

Since our last teleconference, we have established production from the Borum and Basham sandstones in our 2005 Midway Prospect test, the USA #1-24.  In the 1st quarter of 2006, we drilled an additional exploration test in the southern portion of our Midway acreage.  This well, the USA #1-4, encountered 97 feet of potential pay in the Basham interval at approximately 5,000’ and tested at a rate of 1.8 MMcf per day.  We expect this well, which we operate with a 60% working interest, to be on production in September.  We expect to drill a third exploration test on our Midway acreage in the 3rd quarter.  

East Texas

In East Texas, we continue to be active in our Overton field and the Angelina River Trend.  In the 1st half of 2006 we invested approximately $113.6 million in East Texas and spudded 43 wells: 38 at Overton and 5 at Angelina River.  We currently have 4 rigs drilling at Overton with an additional rig in the Angelina River Trend.  In July, we released two third-party rigs that had been drilling in our Overton area.  In our opinion, the day rates being charged for these rigs had become non-competitive with other rigs available in the market.  We have contracted with another drilling company to bring one of their rigs into Overton in August.  Additionally, we expect to bring two company-owned drilling rigs into East Texas by the end of 2006.  Both these rigs and the newly-contracted third-party rig, are expected to result in lower overall drilling costs and higher returns on our investment.  Due to the release of the two third-party rigs, we now expect to drill approximately 68 wells at Overton in 2006, as compared to our original plan of drilling 83 wells.  We continue to maintain a 100% success rate at Overton after drilling over 290 wells since we acquired the field in 2000.  

Production from our Overton Field was approximately 0.2 Bcfe less than expected due to curtailment issues which were resolved late in the quarter.  Delays in rig deliveries in our Fayetteville Shale Play early in the year, along with these temporary curtailment issues and changes in our current drilling plans in East Texas have resulted in a slight decrease in our oil and gas production guidance to 73.0 to 75.0 Bcfe for the full year 2006.

In addition to Overton, we continue to expand our holdings at the Angelina River Trend in Nacogdoches County, Texas.  At December 31, 2005, we held approximately 14,000 gross acres.  Since this time, we have leased an additional 31,100 gross acres, including 13,300 gross acres in the 2nd quarter.   In the 2nd quarter, we completed the Isaacs #2 well.  This well had a peak rate of 2.2 MMcf perday from the Travis Peak at approximately 11,500’.  We are optimistic that our growing position here may provide significant drilling inventory next year and beyond.  

Permian Barnett

Moving on to the Permian Basin, we discussed in our last teleconference that we have approximately 50,000 acres in the emerging Barnett Shale play in the Permian Basin of West Texas.  In the 2nd quarter, we drilled and completed a well in our Popeye prospect and have spudded a well in our Coronado prospect area, both in Culberson County.  The Popeye well, the State Street State #701 is currently being tested. The Dela Minerals 3 State #701, our first well in Coronado is at 7,000’ on its way to a total depth of 12,600’.  We expect to reach TD in early September.

Summary

In summary, we are very encouraged by our continued success in our Fayetteville Shale project.  Gross production is up to 50 MMcf per day, and our recently completed wells continue to outperform.  We currently have 10 rigs running and are ramping to 19 or 20 rigs by the end of the year.  Overall, our programs in the Arkoma Basin, East Texas, and the Permian Basin are performing well and we are looking forward to continued strong results in the remainder of 2006.  We are on track to achieve 20% to 23% true organically driven production growth for 2006, and 2007 is shaping up as an exciting year for our E&P business.

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

Greg Kerley:

Thank you, Richard, and good morning.  As Harold indicated, we had another record quarter.  Our earnings were up 38% to $.22 per share compared to $.18 for the same period in 2005. Our reported earnings included approximately $.03 per share of non-recurring items reflecting the gain on the sale of our interest in the NOARK Pipeline System and a one-time adjustment to record additional deferred income tax expense related to recently enacted tax legislation in the state of Texas.

 Our net cash provided by operating activities (before changes in operating assets and liabilities) was $84.3 million during the second quarter, up 30% over the prior year.

 Operating income for our E&P segment was $49.5 million for the quarter, up 2% from the prior year, as the effects of increased production volumes and higher commodity prices were largely offset by increases in our operating costs and expenses.

The average price realized for our gas production was $6.23 per Mcf for the quarter, up from $5.71 a year ago.  Our hedging activities increased our average gas price by $0.07 during the second quarter of 2006, primarily due to our favorable basis hedges.

Our current hedge position, which consists primarily of costless collars, provides us with a solid level of cash flow protection while still allowing us to retain considerable upside.  We have hedged approximately 70 to 75% of our targeted 2006 gas production and 15 to 20% of our targeted oil production.  We also have approximately 65 to 70% of the basis differentials for our gas production protected for the remainder of 2006 through financial basis hedges and gas sales arrangements.  Assuming an average NYMEX commodity price of $7.00 per Mcf, we expect our average realized price to be approximately $0.45 to $0.55 per Mcf lower than average NYMEX spot market prices for the remainder of 2006.

Lease operating expenses per unit of production were $0.64 per Mcfe in the second quarter, up from $0.43 in the same period last year.  The increase primarily results from higher gathering and compression costs related to our Fayetteville Shale play.  

General and administrative expenses per unit of production were $0.60 in the second quarter, up from $0.39 during the prior year period.  The increase was due primarily to higher compensation and other costs associated with our increased staffing levels to meet the demands of our expanding operations, primarily related to developing our Fayetteville Shale play.  Over the past year we have made a significant investment in time and resources to meet our staffing needs and are pleased with the quality of people we have been able to recruit.  We hired 100 people in the first quarter of the year, another 144 during the second quarter, and we expect to hire another 200 to 250 employees by year-end.  Approximately 250 to 275 of our total new hires are expected to be employed by our drilling company.

Our full cost pool amortization rate averaged $1.79 per Mcfe in the second quarter, compared to $1.38 in the same period last year. The higher rate resulted from an increase in our finding and development costs.  Our finding and development costs during 2006 are expected to be heavily impacted by the timing and amount of our reserve bookings related to our Fayetteville Shale play.  

Operating income from our midstream services segment was $800,000 in the second quarter of 2006, down slightly from $900,000 last year, as increased staffing and operating costs for our gathering activities in the Fayetteville Shale were largely offset by the increased margins on gas volumes marketed.

Our utility systems realized a seasonal operating loss of $2.1 million in the second quarter, compared to a loss of $2.4 million for the same period last year.  The increase in operating income was primarily due to the effects of the rate increase we implemented in October 2005, partially offset by increased operating costs and warmer weather.

During the second quarter we completed the sale of our 25% minority interest in the NOARK partnership for $69 million.  We recorded a $10.9 million gain (or $6.7 million after-tax) related to the sale and assumed $39 million of debt obligations of NOARK which we previously guaranteed.  The net proceeds from the sale will be used to help fund our 2006 capital investment program.  

Our total capital investments in the second quarter of 2006 were $207 million and were $374 million for the first half of the year.  

Our balance sheet and financial position remains extremely strong.  At June 30, our balance sheet debt-to-capitalization ratio was 10%, which is the one of the lowest levels in our history, and we had approximately $176 million of short-term cash investments which exceeded our total debt outstanding by $38 million.  We also have access to $500 million of un-borrowed capacity under our current revolving credit facility.  We are extremely well positioned to continue to accelerate our development of the Fayetteville Shale.

Despite the fact that we have been achieving the strongest operating results in our company's history, as well as establishing our best credit profile, our credit rating was downgraded yesterday by S&P to BB+ (stable outlook) from BBB- (negative outlook).  The downgrade did not impact our cost of borrowing under our credit facility.  We were disappointed with the downgrade, especially at a time when we have over 60X interest coverage and one of the lowest debt-to-total cap percentages of any publicly-rated E&P company at 10%.  Unfortunately, it seems that our size and the potential for accelerated development of our Fayetteville Shale play factored heavily in this decision.  

In our earnings release for the quarter, we also updated our guidance for the year, which included increasing some of our projected unit operating costs and expenses and lowering our expected interest expense.  As we continue to implement our drilling program, we expect our production levels to continue to ramp up significantly.  Our targeted production for the third quarter of 2006 is 19 to 20 Bcfe and our targeted production in the fourth quarter is 21.7 to 22.7 Bcfe.  For the full year of 2006, we are targeting oil and gas production of 73 to 75 Bcfe, which equates to growth of 20 to 23% from 2005.

That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

1

Southwestern Energy Company Second Quarter 2006 Earnings Teleconference

August 2, 2006