EXHIBIT 99.1
Slide Presentation dated September 23, 2003
The following slides were presented September 23, 2003 to institutional investors and analysts at the 2003 John S. Herold Pacesetters Energy Conference held at the Hyatt Regency Hotel in Old Greenwich, Connecticut.
(Slide 1)
Southwestern Energy Company
Presentation to 2003 John S. Herold Pacesetters Energy Conference
September 23, 2003
NYSE: SWN
This slide contains a picture of a weathered door lock and key. The attached keychain is inscribed with the Company's strategic formula
. This formula summarizes the Company's belief that the right people doing the right things, wisely investing the cash flow from the underlying assets will create value +.
(Slide 2)
Southwestern Energy Company (NYSE: SWN)
General Information
Southwestern Energy Company is an independent energy company primarily focused on the exploration for and production of natural gas. Our strategy is to add $1.30 to $1.50 in discounted value for every dollar invested in a balanced exploration and production program in the Arkoma and Permian Basins, East Texas and the onshore Gulf Coast.
Market Data as of August 29, 2003
Shares of Common Stock Outstanding | 35,575,442 |
Market Capitalization | $646,000,000 |
Institutional Ownership | 81.0% |
Management Ownership | 7.3% |
52-Week Price Range | $10.87 (10/18/2002) |
| | $18.16 (08/29/2003) |
Investor Contacts
Greg D. Kerley
Executive Vice President and Chief Financial Officer
Phone: | (281) 618-4803 |
Fax: | (281) 618-4820 |
Brad D. Sylvester, CFA
Manager, Investor Relations
Phone: | (281) 618-4897 |
Fax: | (281) 618-4820 |
(Slide 3)
Forward-Looking Statements
This presentation includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than historical financial information, may be deemed to be forward-looking statements. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Investors should carefully consider the risk factors and other information set forth in the Company's Form 10-K in connection with an investment in the shares of the Company's Common Stock. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein inc lude, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations and critical accounting policies, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs, and other equipment, as well as other factors beyond the Company's control, and any other factors listed in the reports the Company has filed or may file with the SEC, which are incorporated by reference.
(Slide 4)
How We're Creating Value
The Company is focused on exploration and production. It is the driver of our growth as shown in the fact that approximately 85% of our 2002 cash flow was from E&P. We currently have 415.3 Bcfe of reserves, 90% of which are natural gas. The average life of those reserves is 10.4 years.
Our strategy is built on organic growth through the drillbit. Our focus is on drilling, not acquiring and we have a solid inventory of drilling prospects for 2004.
Our company's strategy is also built on the formula. This formula summarizes our belief that the right people doing the right things, wisely investing the cash flow from the underlying assets will create value +.
In order to create this added value we are focusing on "PVI". We strive to add $1.30 to $1.50 of discounted value for every dollar we invest.
(Slide 5)
PVI - The Measure of Value Creation
PVI represents the present value added per dollar invested.
This equation can be further broken down as follows:
PVI = | PV10((Price*Mcfe) - (Cost*Mcfe)) |
| Investment |
(Slide 6)
E&P Focused
Slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote areas of active E&P and lines to trace gas distribution pipelines and the Ozark Pipeline.
E&P Segment
The Company's E&P segment had production in 2002 of 40.1 Bcfe (1). We had reserves of 415.3 Bcfe in 2002, 90% of which were natural gas. The average life of those reserves is 10.4 years. Our E&P segment is comprised of four main areas, the Arkoma Basin, the East Texas Overton Field, the Gulf Coast and the Permian Basin. The reserve and production statistics, and the percentage of the whole for each area are as follows:
| Arkoma | East Texas | Gulf Coast | Permian |
Reserves (Bcfe) | 188.7 | 111.0 | 58.5 | 57.1 |
% of Total Reserves | 45% | 27% | 14% | 14% |
Production (Bcfe) | 19.8 | 5.9 | 7.5 | 6.9 |
% of Total Production | 49% | 15% | 19% | 17% (1) |
(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.
In the Arkoma Basin our strategy is to maintain our strong position through workovers and low-risk development drilling. Growth through low-risk infill drilling is our strategy in the East Texas Overton Field. We plan to focus on medium-risk exploration in the Permian Basin and high-potential exploration in the Gulf Coast region.
Utility Segment
The Company's utility segment services 140,000 customers in Northern Arkansas, a territory which includes the 6th fastest growing region in the U.S. according to the U.S. Census Bureau. In November 2002 we filed for an $11.0 million annual rate increase with the Arkansas Public Service Commission.
(Slide 7)
Capital Investments
This slide contains a bar chart that breaks the Company's capital investments down by general business activity, including utility and corporate, property acquisitions, capitalized expenses, leasehold and seismic, development drilling and exploration drilling. The summary of those investments is as follows:
| 2000 | 2001 (1) | 2002 | 2003 Plan |
| ($ in Millions) |
Utility & Corporate | $6.5 | $7.1 | $6.9 | $8.6 |
Property Acquisitions | $6.1 | $0.7 | $0.1 | $2.3 |
Capitalized Expenses | $9.7 | $9.9 | $10.9 | $11.5 |
Leasehold & Seismic | $9.5 | $9.8 | $9.2 | $15.8 |
Development Drilling | $23.7 | $44.2 | $46.3 | $116.7 |
Exploration Drilling | | | | |
Total | $75.7 | $92.5 | $92.1 | $173.6 |
(1) Net of $13.5 million reimbursement from Overton Field partnership.
This slide also contains a pie chart displaying capital investments by area of operation. The results are as follows:
| % of Total Capital Investments |
East Texas | 52% |
Arkoma | 19% |
Gulf Coast | 13% |
Permian | 4% |
Other E&P | 7% |
Utility | 5% |
As the chart shows our E&P capital program is heavily weighted to low-risk drilling in 2003, with 52% or $90.2 million being spent in East Texas and 19% or $33.4 million being spent in the Arkoma Basin. The medium-risk Permian Basin has received 4% or $6.2 million of total capital investments, and the higher-risk, but larger potential Gulf Coast region received 13% or $22.7 million. Over 80% of the E&P capital has been allocated to drilling in 2003. The utility segment is very valuable in that it provides predictable earnings and cash flow.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 8)
Overton Field - An Impact Project
This slide contains a map of Smith County, Texas where the Overton Field production area is located. Existing wells at year-end 2002, wells drilled at June 30, 2003 and development locations for 2003-2004 are denoted. This area consists of 17,600 acres in the Overton Field and an additional 5,800 farm-in acres in the South Overton area. The Company originally purchased 10,800 acres containing sixteen producing wells in 2000 for $6.1 million. The original wells were developed at 640-acre spacing. During 2001 and 2002 an additional 33 wells were drilled with 100% success. The three year average F&D cost for those wells is $0.63/Mcfe. The 2003-2004 drilling program contains plans to downspace to 80-acre spacing, creating 100 plus additional wells. Twenty-four wells were drilled in the first half of 2003. There is also the potential for further downspacing in the future. A summary of the Overton Field development potential is as follows:
| | Approximate | Reserve |
| Well | Spacing | Potential |
| Count | (Acres) | (Net Bcfe) |
Original Wells | 16 | 640 | 22 |
2001 Development | 15 | 400 | 36 |
2002 Development | 18 | 250 | 53 |
2003 Proposed Development | 55 | 120 (1) | 97 (1) |
2004 Proposed Development | | | |
Total | 157 | 80 (1) | 293 |
(1) In higher potential areas.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 9)
Overton Economics
Typical First Year Economics:
Revenues | $4.00 per Mcfe |
Production costs | $0.30 per Mcfe |
Cash netback | $3.70 per Mcfe |
F&D costs | $0.85 per Mcfe |
Total Life Economics:
Completed well cost | $1.5 MM (1) |
Pretax ROR | 35% (2) |
Pretax PVI | 1.9 (2) |
- Current completed well cost estimate.
- Assumes $4.00 per Mcf flat pricing and gross EUR of 2.2 Bcfe per well.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 10)
Overton Field Gross Production
The graph contained in this slide displays the Overton Field gross production rate for the years 2000 to 2002. The potential gross production rate for 2003 and 2004 is also given under both an accelerated drilling program and under an eighteen well per year program.
The Overton Field's net production for the same years is as follows:
| Bcfe |
2000 | 0.3 |
2001 | 2.3 |
2002 | 5.9 |
2003 Forecast (1) | 10 - 13 |
2004 Forecast (1) | 18 - 20 |
The total number of wells under the two given drilling program options are as follows:
| Dec-01 | Dec-02 | Dec-03 | Dec-04 |
18 Well Drilling Program | 31 | 49 | 67 | 85 |
Accelerated Drilling Program (1) | 31 | 49 | 104 | 157 |
- Assumes accelerated development of Overton with equity offering.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 11)
Arkoma Basin
This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin production area. The Ranger Anticline and Haileyville prospects, and the area known as the Fairway are further noted. The 2003 capital program includes the drilling of 35 to 40 new wells in the Basin and the performance of 60 workovers. In addition, recent approval was given in the Ranger Anticline area to develop the field at 80-acre spacing.
The Arkoma Basin serves as a "legacy asset" for our Company. This area provides a stable production/reserve base and low-risk drilling opportunities with some upside exploration potential. In addition, our 60 years of experience in the Basin and our large acreage position of 385,000 gross acres and 263,000 net acres, provide us with a distinct competitive advantage over other producers.
Statistics for the entire Arkoma Basin, and the Haileyville and Ranger Anticline prospects are given as follows:
Arkoma Basin Three Year Average Results:
Reserve replacement | 97% |
LOE cost (incl. Taxes) ($/Mcf) | $0.30 |
F&D cost ($/Mcf) | $1.08 |
Ranger Anticline Prospect Results:
Success | 17/20 wells |
Net EUR | 22.3 Bcf |
F&D/Mcf | $.74 |
Haileyville Prospect Results:
Success | 16/24 wells |
Net EUR | 9.3 Bcf |
F&D/Mcf | $.82 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 12)
Ranger Anticline
This slide contains a map of the Ranger Anticline prospect. Our exploratory acreage and acreage held by production are designated with shading. Producing wells at 6/30/03 and 2003 proposed wells are also shown.
In early 2003, we received approval to downspace the Ranger Anticline field to 80 acres per well. We plan to drill fourteen wells in 2003 and have the potential for significant exploration and development drilling thereafter. We hold a large acreage position of 4,500 gross developed acres and 35,200 gross exploratory acres. Our average working interest in the area is 50% - 100%. A summary of the Ranger Anticline development potential on our held by production acreage is as follows:
| | | Approx. | Reserve |
| | Well | Spacing | Potential |
| | Count | (Acres) | (Net Bcfe) |
Producing Wells at 12/31/02 | 13 | 345 | 17 |
Wells Drilled in 1st Half of 2003 | 4 | 265 | 5 |
Remaining 2003 Development | 10 | 165 | 11 |
Potential Future Locations: | | | |
Development | 13 | 110 | 12 |
Prob/Poss Locations | | | |
TOTAL | 56 | 80 | 60 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 13)
Gulf Coast Exploration
This map shows Company exploration activity within the Louisiana onshore Gulf Coast region. The Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone exploration areas in particular are highlighted. Shading denotes the areas where 3D seismic information either already existed or was acquired/purchased in 2002. Specifically, a license to over 1,000 square miles of 3-D shelf data was acquired in 2002. In addition, the 135-sqare mile Duck Lake 3-D project data is now in-house. Duck Lake is a highly prospective area in St. Martin and St. Mary Parishes where we are the operator and a 50% working interest owner. Drilling in the area is to commence in 2003.
The Gulf Coast map also points out areas of discovery and the locations of 2003 prospect wells. Out of the last nineteen wildcats drilled in South Louisiana we have produced eight discovery wells. Three-year average results for the region are as follows:
Reserve Replacement | 246% |
LOE Cost (incl. Taxes) ($/Mcfe) | $0.65 |
F&D Cost ($/Mcfe) | $1.83 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 14)
How Have We Been Doing?
The graph contained on this slide shows how the implementation of a new management and E&P team along with a new strategy has affected F&D Cost, Reserve Replacement and PVI.
| 1997 | 1998 | 1999 | 2000 (1) | 2001 | 2002 |
F&D cost ($/Mcfe) | $2.53 | $1.10 | $1.20 | $.99 | $1.11 | $1.02 |
Reserve replacement | 77% | 129% | 150% | 196% | 224% | 209% |
PVI ($/$) | $ .56 | $1.17 | $1.07 | $1.30 | $1.40 | $1.33 |
Note that all metrics calculated exclude reserve revisions.
(1) PVI metrics were calculated using pricing in effect at year-end with exception to the year 2000 which was calculated at $3.00 per Mcf natural gas price.
(Slide 15)
The Road to Value Creation, V+
This slide summarizes the strategy by which the Company plans to continue to create added value in everything it does.
Invest in the Highest PVI Projects | |
| | Overton PVI = 1.9 at $4.00 gas price |
Maximize Cash Flow | |
Stay the Course with Our E&P Strategy | |
| | Low-risk development balanced with high-potential exploration. |
Deliver the Numbers | |
| | Production and reserve growth |
| | Add value for every dollar invested |
Continue to Tell Our Story | |
| | We're not in the clubhouse, yet. |
