Southwestern Energy Second Quarter 2007 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 - CEO, President, Chairman
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 results, please call (281) 618-4784 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.
We’ve had a very productive first half of the year and have made a lot of progress in our Fayetteville Shale play. Our production growth of 57% over the second quarter last year shows the strong impact our Fayetteville Shale play is having on our results. However, we are also having very good results in our base activities in East Texas and the conventional Arkoma Basin. We’ve continued to grow our capabilities to carry out the increased activity level as we’ve added 176 new employees in the first half of this year.
For the remainder of 2007, we plan to focus our Fayetteville drilling activity in areas that have been identified as better performing and, where possible, in areas where we have 3-D seismic data. Generally now, we are moving to the slickwater fluid systems for our frac jobs in the Fayetteville and have begun drilling longer laterals which, coupled with additional completion stages, seem to result in better wells. So, we are continuing to make progress in our Fayetteville project and are seeing good results in our other base project areas.
I’d like to now turn the conference over to Richard for a more detailed update on our operations and then to Greg for a discussion of our financial results.
Richard Lane – EVP and President of E&P Operations
Good morning. Our natural gas and crude oil production totaled 25.8 Bcfe for the 2nd quarter of 2007, up from 16.4 Bcfe for the 2nd quarter of 2006. The increase was primarily due to growth from our Fayetteville Shale play, which produced 10.7 Bcf in the 2nd quarter of 2007, compared to 8.2 Bcf in the 1st quarter of 2007 and 1.8 Bcf in the 2nd quarter of 2006. We continue to estimate that our full year production will range between 107.0 and 110.0 Bcfe.
In the first half of 2007, we invested approximately $670 million in our exploration and production activities and participated in drilling 304 wells. Of the 304 wells, 142 were productive, 5 were dry, and 157 were in-progress on June 30th for an overall success rate of 97%. Of the $670 million invested, approximately $568 million, or 85%, was for drilling wells. We currently have 31 rigs running, 15 deep and 4 shallow rigs in the Fayetteville Shale Play, 7 rigs in East Texas, one rig in North Louisiana, and 4 rigs in the conventional Arkoma Basin.
Fayetteville Shale Play
In the Fayetteville Shale Play, we drilled and completed 62 wells in the 2nd quarter. The wells drilled ranged in total vertical depth from approximately 2,300 to 5,300 feet with horizontal sections that averaged approximately 2,550 feet.
During the 2nd quarter, our time to drill to total depth averaged 18 days from re-entry to re-entry compared to a 1st quarter average time of 20 days. Average completed well costs during the 2nd quarter were $2.9 million per well compared to the $2.6 million average cost for wells completed in the 1st quarter. The increased cost is primarily due to drilling and completing wells with longer horizontal laterals. Lateral lengths for 2nd quarter wells averaged 2,550 feet compared to 2,100 feet in the 1st quarter.
For the remainder of 2007, the majority of our Fayetteville Shale drilling activity will be in the areas that have been identified as better performing to date and, where possible, where we have 3-D data. We plan to complete the vast majority of wells going forward using slickwater stimulations. We also plan to use open-hole packer systems on approximately 30% of our remaining wells. Our analysis indicates that both the slickwater stimulations and the open-hole packer systems yield better performing wells.
We are also seeing better well results from drilling longer horizontal laterals. In the 2nd quarter, we drilled 10 wells with laterals longer than 3,000 feet. These wells had an average initial production rate of 2.1 MMcf per day and an average estimated cost of $3.1 million per well. Our Bartlett well, located in the South Rainbow pilot area, had a 3,700-foot horizontal lateral. After being completed with an eight-stage slickwater stimulation, the well had an initial production test rate of 4.4 MMcf per day and was producing 4.0 MMcf per day after being on production for 25 days.
Our most recent wells, those put on production from July 1st through July 21st, have an average initial production rate of 2.2 MMcf per day and the last 10 wells we completed have an average initial production rate of 2.6 MMcf per day. Of these 10 wells, three had initial rates at over 4.0 MMcf per day. In the southeastern part of the play, the Reaper #1-12 in our Bull pilot, was put on production in mid July at 4.6 MMcf per day (our highest rate to date).
In our press release, we provided an updated normalized average daily production for horizontal wells completed with slickwater and/or crosslinked gel frac fluids. As we have noted before, we are continuing to see variability in Fayetteville Shale well performance across our pilot areas. As you review this new updated production data, there are a few things worth noting relative to the prior reporting period. One, the initial production rate is approximately 200 Mcf per day higher, showing the effect of recently improved well results. Second, slightly lower rates in the 0 to 180 day period from some poorer wells like our East Cutthroat area and, third, a flattening of the decline in our oldest producing wells.
Production from the Fayetteville Shale Play area is now at approximately 200 MMcf per day, including approximately 10 MMcf from five conventional wells in four pilot areas. This production milestone is particularly notable in that we began drilling wells just three years ago and at 200 MMcf per day we have doubled the rate during 2007. Going forward, we are confident that we have adequate pipeline takeaway capacity to keep pace with our growing production here.
Four of our five conventional wells are producing from the Hale reservoir. The remaining well is producing from the Orr sand. We are currently completing four additional wells in three more pilot areas east of where we currently have established conventional production and are planning on drilling several more conventional tests before the end of the year. We continue to be very encouraged by our conventional exploration program in the Morrowan section and have begun to recognize some deep potential below the Mississippian section. This should be further enhanced by our on-going seismic program.
Our second horizontal test of the Moorefield Shale, which directly underlies the Fayetteville Shale on the eastern portion of our acreage appears to have treated out of zone and has produced mostly water. We are currently analyzing the Brooks #3-27’s frac data to understand this. We continue to believe that the Moorefield is prospective and are currently completing the Brooks #1-20 in our Midge pilot and the Russell #1-35 in our Tiger pilot in the Moorefield Shale. We also plan two additional Moorefield tests by the end of the year.
We plan to invest approximately $950 million in the Fayetteville Shale project area during 2007. This capital investment includes participating in approximately 400 horizontal wells in the Fayetteville Shale play. We are integrating many new people into our operations, experimenting with new technology, and moving forward with assessing more of our acreage.
Arkoma Basin Conventional
Moving on to our conventional Arkoma Basin properties, we have had a very positive first six months of 2007. We have invested approximately $86 million here drilling 59 wells of which 45 were productive and 11 were still in progress at the end of the quarter. We are continuing to put good wells on production at our Ranger Anticline and Midway areas. As a result, production from the conventional Arkoma basin was 6.0 Bcf for the quarter, up 25% from the 2nd quarter of 2006. In the 2nd quarter, we placed 12 wells on production at Ranger with an average initial production of 2.6 MMcf per day per well. Our current gross production at Ranger is approximately 50 MMcf per day and we estimate that we have an inventory of over 140 potential wells remaining to be drilled here. At our Midway project, we have drilled enough to know we have opened up a new gas field. Our initial test well here was drilled in late 2005. Since this time , we have drilled 21 wells with an additional 15 to 20 wells scheduled for the remainder of 2007.
East Texas Field
In East Texas, we continued our active drilling programs with 4 rigs at Overton and 3 rigs at our Angelina River Trend. In the first six months of 2007, we invested approximately $100 million drilling 26 wells at Overton, 13 wells at Angelina River, one well at our Jebel prospect, and two wells in other areas. All of these wells were either productive or in progress at the end of the quarter.
Production from East Texas was 7.5 Bcfe in the 2nd quarter, compared to 7.8 Bcfe last year. We have nearly offset the decline attributable to slowing down our drilling program at Overton by ramping up our activity in other East Texas projects.
We are currently testing the first well on our Jebel prospect that we drilled in the 2nd quarter. The Timberstar #1 is located on approximately 16,500 gross acres that we farmed-in late last year and is currently testing at a rate of 3.4 MMcf per day from the Travis Peak while still cleaning up. Since obtaining the farm-in, we have added approximately 15,900 additional acres in the area for a total of 32,400 gross acres. In addition to the Travis Peak, we believe that this acreage may be a candidate for horizontal drilling in the James Lime. We are currently drilling our second well in the area.
Summary
In summary, we are pleased with our year-to-date results. Our Fayetteville Shale play is advancing extremely well. It holds a tremendous inventory of wells for us to pursue and to organically increase our production and reserves at very meaningful rates. Our other assets are performing well also, and together our producing property portfolio provides a predictable, long lived producing base with more opportunities on them to develop.
I will now turn it over to Greg Kerley who will discuss our financial results.
Greg Kerley – EVP and CFO
Thank you, Richard, and good morning. Our earnings for the second quarter were $47.6 million, or $0.28 per share, up 29% from the prior year. Our record financial results were driven primarily by the positive effect on our earnings of our increased production volumes and higher realized natural gas prices. Net cash provided by operating activities before changes in operating assets and liabilities increased to $146.8 million, up 74% from the prior year.
We produced a record 25.8 Bcfe in the second quarter, and realized an average gas price of $6.90 per Mcf, which was up $0.67 from the prior year period. Our commodity hedging program increased our average gas price during the quarter by $0.07 per Mcf.
Our current hedge position, which consists of fixed price commodity swaps and collars, provides us with support for a strong level of cash flow. For the remainder of the year, we have approximately 75% of our projected natural gas production hedged. We have 26 Bcf hedged with fixed price swaps at an average price of $7.90 per Mcf and we have 17 Bcf hedged through price collars with an average floor price of $6.85 and an average ceiling price of $10.64. We also have hedged 85 Bcf in 2008 and 48 Bcf in 2009 at even higher prices than those in 2007. Our detailed hedge position is included in our Form 10-Q which was filed yesterday.
Our lease operating expenses per unit of production were $0.73 per Mcfe during the second quarter, up from $0.64 during the same period last year. The increase was primarily due to increases in gathering and other costs related to our operations in the Fayetteville Shale. For the full year, we expect our per unit lease operating cost to range between $0.82 and $0.87 per Mcfe.
Taxes other than income taxes were $0.21 per Mcf during the second quarter, down from $0.39 in the prior year period. We expect our rate to range between $0.21 and $0.26 for the full year, assuming a $7.00 average NYMEX gas price.
General and administrative expenses per unit of production were $0.48 per Mcfe in the second quarter, down from $0.60 in the prior year period. The decrease in general and administrative costs per unit of production was primarily due to our increased production volumes. We also hired a total of 79 new employees during the second quarter. We expect our general and administrative expenses per unit of production to range between $0.41 and $0.46 per Mcfe for the calendar year.
Our full cost pool amortization rate was $2.41 per Mcfe in the second quarter, and we expect our average rate for the year to range between $2.20 and $2.40 per Mcfe.
Operating income from our midstream services segment was $2.3 million in the second quarter, up from $800,000 in the same period a year ago. The increase in operating income was due to increased gas gathering revenues related to the Fayetteville Shale play.
Our natural gas distribution segment realized a seasonal operating loss of $1.7 million in the second quarter, compared to a loss of $2.1 million during the same period last year. The improved results were primarily due to colder weather. In July, the Arkansas Public Service Commission approved a rate increase for our gas utility of $5.8 million, which became effective today.
At June 30, 2007, we had total indebtedness of approximately $497 million (including $360 million borrowed on our revolving credit facility), resulting in a capital structure of 24% debt and 76% equity. Our $1.3 billion planned capital program is expected to be funded by proceeds from internally-generated cash flow, borrowings under our revolving credit facility and/or funds raised in the public debt or equity markets. Assuming our capital program is funded entirely through cash flow and borrowings we expect our long-term debt-to-total capitalization ratio to be approximately 35% at year-end 2007.
That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.
Southwestern Energy Company Second Quarter 2007 Earnings Teleconference Transcript
August 1, 2007
