EXHIBIT 99.1
Slide Presentation dated September 2, 2004
The following slides were presented September 2, 2004 to investors and analysts at the Southwestern Energy Company headquarters in Houston, Texas.
(Slide 1)
Southwestern Energy Company
Presentation to Sterne, Agee & Leach, Inc., September 2, 2004
This left side of this slide contains a picture of a snow-capped volcano. The caption above reads "The Power Within." The Company's formula
is located in the bottom right corner. The top right corner of this slide contains a box with a picture of an oil derrick and "75 years SWN 1929 - 2004."
(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 at least $1.30 in discounted value for every dollar invested in a focused exploration and production program in the Arkoma and Permian Basins, East Texas and the onshore Gulf Coast.
Market Data as of August 31, 2004
Shares of Common Stock Outstanding | 36,167,339 |
Market Capitalization | $1,286,000,000 |
Institutional Ownership | 86.7% |
Management Ownership | 7.0% |
52-Week Price Range | $17.17 (9/4/2003) |
| | $35.57 (8/31/2004) |
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
All statements, other than historical financial information, 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. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, 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, the impact of federal, state and local government regulation, the financial impact of accounting regulations and critical accounting policies, changing market conditions and prices, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field personnel, services, drilling rigs and other equipment, the extent to which the Fayetteville Shale play can replicate the results of other productive shale gas plays, the potential for significant variability in reservoir characteristics of the Fayetteville Shale over such a large acreage position, as well as various other factors beyond the company's control, and any other factors listed in the reports the company has filed with the Securities and Exchange Commission. A discussion of these and other factors affecting the company's performance is included in the company's periodic reports filed with the Securities and Exchange Commission, including its Annual Report on Form 10-K for the year ended December 31, 2003. Unless otherwise required by applicable securities laws, the company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
(Slide 4)
About Southwestern
| * Focused on domestic production of natural gas. |
| | * 503 Bcfe of reserves; 91% natural gas; 12.2 R/P at year-end 2003. |
| |
| * Track record of adding significant reserves at low costs. |
| | * Since 1999, we've averaged production growth of 6% per year, 230% reserve replacement, F&D cost of $1.10 per Mcfe. |
| | |
| * E&P strategy built on organic growth through the drillbit. |
| | * Approximately 80% of 2004 planned E&P capital allocated to drilling. |
| | |
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to over $1 billion today. |
| |
| * Strategy built on the Formula: |
| | The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+. |
(Slide 5)
Current Highlights
2003
* Follow-on equity offering completed in March 2003. Raised $103 million to accelerate development drilling at Overton Field. |
| * Improved our debt-to-capital ratio to 45% at 12/31/03 from 66% at 12/31/02. |
| | |
| * Record operating and financial results. |
| | * Record reserve additions of 144.5 Bcfe, replacing 351% of production. |
| | * Reserve growth of 21% to 503 Bcfe. |
| | * Record production of 41.2 Bcfe. |
| | * Record net income of $48.9 million. |
| | * Record EBITDA(1) of $152.3 million. |
| | * Received $4.1 million annual rate increase for utility. |
| | |
| * New $300 million revolving credit facility put in place January 2004. |
First Six Months 2004
| * Production of 24.0 Bcfe, up 27% over 18.9 Bcfe for first six months in 2003. |
| * Record net income of $45.3 million, up 95% over net income for same period in 2003. |
| * CapEx of $126.8 million, up 58% over 1H 2003 level, yet debt-to-capital ratio decreased to 42%. |
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 34.
(Slide 6)
Proven Track Record
This slide contains bar charts for the periods ended December 31.
| 1999 | 2000 | 2001 | 2002 | 2003 |
Production (Bcfe) | 32.9 | 35.7 | 39.8 | 40.1 | 41.2 |
Reserve Replacement | 150% | 196% | 224% | 209% | 351% |
EBITDA ($MM)(1) | $76.1 | $103.2 | $134.6 | $99.8 | $152.3 |
F&D Cost ($/Mcfe) | $1.20 | $0.99 | $1.11 | $1.02 | $1.18 |
Note: Reserve data excludes reserve revisions.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 34.
(Slide 7)
E&P Focused
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote the Arkoma and Permian Basins, the Gulf Coast region and the East Texas region. Lines trace gas distribution pipelines and the Ozark Pipeline.
E&P Segment
| * 2003 Reserves: 503 Bcfe |
| * 91% Natural Gas |
| * 82% Proved Developed |
| * Reserve Life: 12.2 years |
| * 2003 Production: 41.2 Bcfe |
Arkoma
| * Reserves - 211.7 Bcf (42%) |
| * Production - 18.9 Bcf (46%) |
| * Maintain our strong position through low-risk development drilling and workovers. |
East Texas (Overton)
| * Reserves - 196.3 Bcfe (39%) |
| * Production - 13.6 Bcfe (33%) |
| * Grow through low-risk infill drilling. |
Gulf Coast
| * Reserves - 39.5 Bcfe (8%) |
| * Production - 4.5 Bcfe (11%) |
| * Reduce our high-risk exploration. |
Permian
* Reserves - 55.6 Bcfe (11%) |
* Production - 4.2 Bcfe (10%) |
* Focus on medium-risk exploration. |
Utility Segment
| * 142,000 customers in N. Arkansas |
| * 6th fastest growing region in U.S. |
| * Received $4.1 MM annual rate increase Oct. 2003 |
(Slide 8)
Capital Investments
This slide contains a bar chart of Company capital investments, summarized as follows:
| | | | | 2004 |
| 2001 | | 2002 | 2003 | Plan |
| ($ in millions) |
Utility & Corporate | $7.1 | | $6.9 | $9.3 | $9.5 |
Property Acquisitions | $0.7 | | $0.1 | $ - | $14.4 |
Cap. Exp. & Other | $9.9 | | $10.9 | $12.4 | $19.3 |
Leasehold & Seismic | $9.8 | | $9.2 | $19.0 | $18.0 |
Development Drilling | $44.2 | | $46.3 | $119.7 | $162.3 |
Exploration Drilling | $20.8 | | $18.7 | $19.8 | $30.0 |
Total | $92.5 | (1) | $92.1 | $180.2 | $254.0 |
This slide also contains a pie chart of Company's planned 2004 capital investments by area of operation, summarized as follows:
| % of Total |
| Capital Investments |
East Texas | 51% |
Arkoma | 20% |
Gulf Coast | 5% |
Permian | 11% |
Desoto Unconventional | 8% |
| New Ventures | 1% |
Utility | 4% |
| * E&P capital program heavily weighted to low-risk drilling in 2004: |
| | * Low-risk East Texas ($129.4 MM, 51%) and Arkoma ($51.2 MM, 20%), |
| | * Medium-risk Permian Basin ($26.7 MM, 11%) and |
| | * Higher-risk, but larger potential Gulf Coast ($13.5 MM, 5%). |
| | |
| * Desoto - Unconventional Arkoma ($19.5 MM, 8%). |
| | * Invested $11.0 MM in 2003 to acquire approx. 343,000 net undeveloped acres in new shale play. |
| | * Currently hold approx. 455,000 net undeveloped acres + 120,000 net acres HBP. 20 test wells planned in 2004. |
| | |
| * Approximately 80% of E&P capital allocated to drilling in 2004. |
(1) Net of $13.5 million reimbursement from Overton Field partnership.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 9)
Arkoma Basin
This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin. The Ranger Anticline, Haileyville and the area known as the Fairway are further noted. The Wedington Incongruity and a portion of the Desoto Unconventional(1) play are also designated.
* Conventional Play: |
| * 60+ years of experience in the basin, large acreage position of 256,000 net acres. |
| | * 2004 capital program includes drilling over 80 wells and 95 workovers. |
| | |
* New Unconventional Shale Play: |
| * Fayetteville Shale project results to date have been encouraging. If successful, could have a significant positive impact. |
| * Currently hold approx. 455,000 net undeveloped acres and approx. 120,000 net acres held by conventional production in play area. |
Arkoma Basin 2001-2003 Avg Results:
Reserve replacement: | 116% |
LOE Cost (incl. Taxes) ($/Mcf): | $0.38 |
F&D Cost ($/Mcf): | $1.14 |
Ranger Anticline (inception thru 6/30/04):
Success: | 33/40 wells |
Net EUR: | 42.0 Bcf |
F&D/Mcf: | $.81 |
Haileyville (inception thru 6/30/04):
Success: | 23/31 wells |
Net EUR: | 11.4 Bcf |
F&D/Mcf: | $.75 |
(1) For illustrative purposes only. Shaded area does not delineate actual play area.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 10)
Ranger Anticline
This slide contains a map of the Ranger Anticline prospect with the Company's exploratory acreage and acreage held by production designated with shading. Also shown are SWN's producing wells at 6/30/04, 2004 proposed wells, the Smith #1-10, the Lewellen #1-12 and Quarry Heights #1-17 completing wells and the Albright #1-7 well.
Ranger Anticline (inception thru 6/30/04):
Success: | 33/40 wells |
Net EUR: | 42.0 Bcf |
F&D/Mcf: | $.81 |
* In July 2004, received approval to downspace field to 560 feet between wells. |
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* Current acreage position of 4,400 gross developed acres and 37,100 gross exploratory acres. |
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* Average working interest 50% - 100%. |
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* SWN plans to drill approximately 20 wells in area in 2004. |
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* Area has significant upside potential. |
Ranger Anticline Potential:
| | Reserve |
| Well | Potential |
| Count | (Net Bcfe) |
Producing Wells at 12/31/02 | 13 | 17 |
Successful Wells in 2003 | 9 | 12 |
2004 Drilling Program | 20 | 23 |
| | | |
Potential Future Locations | | |
| Lower-Risk Locations | 45 | 41 |
| | Other Contingent Locations | 132 | 128 |
| TOTAL | 219 | 221 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 11)
Desoto Project - Mississippian Shale Deposition
This slide contains a map of Oklahoma, Arkansas, and portions of Louisiana and Texas. Shading denotes the Fayetteville and Caney Shales in the Arkoma Basin, the Barnett Shale in the Fort Worth Basin and the Frontal Belt area.
* The Fayetteville Shale is a Mississippian-age shale that is the geologic equivalent of the Caney Shale in Oklahoma and the Barnett Shale in north Texas.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 12)
Desoto Project - Mississippian Shale Equivalents
This slide contains a geological comparison of the Barnett, Caney and Fayetteville Shales.
| * Barnett Shale |
| | * Thickness (gross): 200' to 500' |
| | |
| * Caney Shale |
| | * Thickness (gross): 20' to 180' |
| | |
| * Fayetteville Shale |
| | * Thickness (gross): 50' to 325' |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 13)
Desoto Project - Fayetteville Shale
* Current data relative to total organic content, thermal maturity and total gas content compares favorably with other productive shale gas plays, including the Barnett. |
| |
* The shale appears to be laterally extensive, ranging in thickness from 50 to 325 feet, and ranging in depths from 1,500 to 6,500 feet. |
| |
* Southwestern is currently in the lead on this play. |
| * During 2003, we acquired approx. 343,000 net undeveloped acres in the play. |
| * During 2004, we have acquired approx. 112,000 additional net undeveloped acres to date and currently hold approx. 455,000 net undeveloped acres. |
| * Also control approx. 120,000 net acres held by conventional production in play area. |
| * Recently drilled 4 Fayetteville shale tests and results to date are encouraging. |
| * Remaining in 2004: Drill 16 additional wells to determine aerial extent, variability and optimal completion techniques. |
| |
* If our testing yields positive results, we expect that our activity in the play would increase significantly over the next several years. |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 14)
East Texas - Overton Field
This slide contains a map of Smith County, Texas where the Overton Field is located. Existing wells at year-end 2002, 2003 and 2004 development well locations are denoted. It is stated that the Overton Field contains 17,900 acres and the South Overton Farm-in Acreage contains 6,500 acres.
* Purchased original 10,800 acres and 16 producing wells for $6.1 million in 2000 (developed at 640-acre spacing). |
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* Drilled 90 wells in 2001-2003 with 100% success. |
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* Plan to drill 74 wells in 2004, a portion of which will be at 40-acre spacing. |
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* A large portion of the field will likely require 40-acre spaced wells to adequately develop the field. |
Overton Field reserve potential:
| | Approx. | Reserve |
| Well | Spacing | Potential |
| Count | (Acres) | (Net Bcfe) |
Original Wells | 16 | 640 | 22 |
2001 - 2002 Development | 33 | 365 | 89 |
2003 Development | 57 | 170 | 102 |
Planned 2004 Development | 74 | 100 | 105 |
| | | |
Potential Future Development | | | |
| | Locations @ $5.00 Gas | 130 | 70 | 131 |
| Locations @ $6.00 Gas | 187 | 50 | 174 |
Overton Field 2001-2003 Average Results:
Reserve Replacement: | | 902% |
LOE Cost (incl. Taxes) ($/Mcfe): | | $0.46 |
F&D Cost ($/Mcfe): | | $0.82 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 15)
Overton Field Gross Production
The graph contained in this slide displays the Overton Field gross production rate (MMcfe/d) from the year 2000 to December 2004 and the potential gross production rate for 2004 under both an accelerated drilling program and under an eighteen well per year program.
Overton Field Net Production:
| Bcfe |
2000 | 0.3 |
2001 | 2.3 |
2002 | 5.9 |
2003 | 13.6 |
2004 Forecast | 19 - 21 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 16)
Overton Field - Improved Drilling Results
This slide of drilling days versus depth portrays the improved drilling rate in the Overton Field since its purchase from Fina in 2001. Fina's average drilling rate was 55 days. Upon the Field's purchase in 2001 we decreased that rate to 35 days. It was further decreased to 27 days in 2002, 23 days in 2003 and 22 days through June 30, 2004.
* Reduced drilling time by >50%. |
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* Increased initial production by 200%. |
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* Increased gross reserves by 60% (avg. EUR of 2.2 Bcfe per well in 2003) |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 17)
2004 Exploration
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shading to denote areas of Company operations. An exploded map of a portion of New Mexico details the River Ridge discovery. The Rio Blanco 9 #1 drilling well is shown.
* Gulf Coast exploration: |
| * Reducing our exposure to high-risk exploration in South Louisiana. |
| * Remaining 2004 program includes drilling 2-3 wells in Gulf Coast area. |
| |
* River Ridge prospect, Lea County, New Mexico: |
| * Currently producing at a gross rate of 36 MMcfe/d with cumulative production of 4.6 Bcfe. |
| * Gross reserve potential of 50+ Bcfe. |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 18)
How Have We Been Doing?
Graph shows F&D cost ($/Mcfe), reserve replacement (%) and PVI ($/$) after new management, a new E&P team and a new strategy were implemented in 1997.
| 1997 | 1998 | 1999 | 2000(1) | 2001 | 2002 | 2003 |
F&D cost ($/Mcfe) | $2.53 | $1.10 | $1.20 | $.99 | $1.11 | $1.02 | $1.18 |
Reserve replacement (%) | 77% | 129% | 150% | 196% | 224% | 209% | 351% |
PVI ($/$) | $ .56 | $1.17 | $1.07 | $1.30 | $1.40 | $1.33 | $1.42 |
Note: All metrics calculated exclude reserve revisions.
(1) PVI metrics calculated using pricing in effect at year-end (except for 2000 which was calculated at $3.00 per Mcf natural gas price).
(Slide 19)
Outlook for 2004
| * Production target of 50.0 - 52.0 Bcfe in 2004 (estimated growth of 21 - 26%). |
| | | 2004 Guidance |
| 2003 Actual | NYMEX Price Assumptions |
| $5.39 Gas(1) | $5.00 Gas | $6.00 Gas |
| $30.83 Oil(1) | $30.00 Oil | $34.00 Oil |
Net Income | $48.9 MM | $72 - $75 MM | $94 - $97 MM |
EPS | $1.43 | $2.00 - $2.07 | $2.60 - $2.68 |
Operating Income | $97.3 MM | $135 - $138 MM | $172 - $175 MM |
Net Cash Flow(2) | $132.3 MM | $190 - $193 MM | $225 - $228 MM |
EBITDA(2) | $152.3 MM | $207 - $210 MM | $242 - $245 MM |
Note: Per share estimates for 2004 assume 36.6 million weighted average diluted shares outstanding.
(1) The average realized prices for our gas and oil production, after the effect of commodity hedge losses and basis differentials, were $4.20 per Mcf and $26.72 per Bbl, respectively, in 2003.
(2) Net Cash Flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 33 and 34.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 20)
Gas Hedges in Place Through 2006
This slide contains a bar chart detailing gas hedges in place by quarter for the years 2004, 2005 and 2006. A summary of these outstanding gas hedges is as follows:
| | | Average Price per Mcf | Percent of Total |
| Type | Hedged Volumes | (or Floor/Ceiling) | Production Hedged |
2004 | Swaps | 7.2 Bcf | $4.00 | 15 - 20% |
| Collars | 26.0 Bcf | $3.92 / $6.62 | 50 - 55% |
2005 | Swaps | 12.6 Bcf | $5.04 | - |
| Collars | 31.0 Bcf | $4.64/ $7.98 | - |
2006 | Swaps | 1.0 Bcf | $5.74 | - |
| Collars | 10.0 Bcf | $4.50/ $8.65 | - |
Note: Southwestern has approximately 426,000 barrels of oil hedged at a fixed WTI price of $28.39 per barrel in 2004 and 360,000 barrels of oil hedged at a fixed WTI price of $33.17 per barrel in 2005 and 120,000 barrels of oil hedged at a fixed WTI price of $37.30 per barrel in 2006.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 21)
The Road to V+
| * Invest in the Highest PVI Projects. |
| | * Accelerate Overton Development. |
| | * Accelerate Ranger Anticline Development. |
| | |
| * Maximize Cash Flow. |
| | |
| * Stay the Course with Our Focused Strategy. |
| | |
| * Deliver the Numbers. |
| | * Production and Reserve Growth. |
| | * Add Value for Every Dollar Invested. |
| | |
| * Continue to Tell Our Story. |
(Slide 22)
Appendix
(Slide 23)
Financial & Operational Summary
This slide contains a table that summarizes the Company's financial and operational indicators.
| 6 Months Ended June 30, | | Year Ended December 31, |
| 2004 | 2003 | | 2003 | 2002 | 2001 | 2000(1) |
| ($ in millions, except per share amounts) |
| | | | | | | |
Revenues | $216.2 | $165.1 | | $327.4 | $261.5 | $344.9 | $363.9 |
EBITDA(2) | 113.8 | 73.4 | | 152.3 | 99.8 | 134.6 | 103.2 |
Net Income | 45.3 | 23.2 | | 48.9 | 14.3 | 35.3 | 20.5 |
Net Cash Flow(2) | 106.8 | 65.2 | | 132.3 | 79.8 | 112.7 | 82.4 |
Diluted EPS | $1.23 | $0.71 | | $1.43 | $0.55 | $1.38 | $0.82 |
| | | | | | | | |
Production (Bcfe) | 24.0 | 18.9 | | 41.2 | 40.1 | 39.8 | 35.7 |
Avg. Gas Price ($/Mcf) | $5.09 | $4.22 | | $4.20 | $3.00 | $3.85 | $2.88 |
Avg. Oil Price ($/Bbl) | $28.55 | $27.54 | | $26.72 | $21.02 | $23.55 | $22.99 |
| | | | | | | | |
Finding Cost ($/Mcfe)(3) | | | | $1.18 | $1.02 | $1.11 | $0.99 |
Reserve Replacement (%)(3) | | | | 351% | 209% | 224% | 196% |
(1) Before the effects of unusual and extraordinary items.
(2) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 33 and 34.
(3) Excluding reserve revisions.
(Slide 24)
SWN is One of the Lowest Cost Operators
This slide contains a bar graph that compares SWN to its competitors in terms of lifting cost per Mcfe of production (3 year average).
| | | Lifting Cost per Mcfe |
| | | of Production |
| | | (3 year average) |
| | | |
Houston Exploration | | $0.57 |
Burlington Resources | | $0.57 |
| Remington Oil & Gas | | $0.58 |
Southwestern Energy Company | | $0.62 |
EnCana | | $0.70 |
Newfield Exploration | | $0.71 |
Patina Oil & Gas | | $0.71 |
Chesapeake Energy | | $0.74 |
| Cabot Oil & Gas | | $0.76 |
Range Resources | | $0.79 |
Apache | | $0.79 |
Pioneer Natural Resources | | $0.82 |
Anadarko Petroleum | | $0.85 |
| Swift Energy | | $0.89 |
XTO Energy | | $0.89 |
Devon Energy | | $0.90 |
| Cimarex Energy | | $0.90 |
| St. Mary Land & Exploration | | $1.05 |
| Forest Oil | | $1.07 |
| Denbury Resources | | $1.14 |
| Magnum Hunter Resources | | $1.14 |
This slide also contains a bar graph comparing SWN to its competitors in terms of drillbit F&D cost per Mcfe (3 year average).
| | | Drillbit F&D Cost |
| | | per Mcfe |
| | | (3 year average) |
| | | |
XTO Energy | | $0.81 |
Southwestern Energy Company | | $1.11 |
| Burlington Resources | | $1.37 |
| Apache | | $1.37 |
Swift Energy | | $1.48 |
EnCana | | $1.51 |
Anadarko Petroleum | | $1.51 |
Patina Oil & Gas | | $1.52 |
| Cabot Oil & Gas | | $1.63 |
Denbury Resources | | $1.72 |
Range Resources | | $1.79 |
| St. Mary Land & Exploration | | $1.93 |
Forest Oil | | $1.95 |
Chesapeake Energy | | $2.00 |
| Remington Oil & Gas | | $2.07 |
| Houston Exploration | | $2.23 |
Newfield Exploration | | $2.76 |
Pioneer Natural Resources | | $2.98 |
| Cimarex Energy | | $3.01 |
| Magnum Hunter Resources | | $3.03 |
| Devon Energy | | $3.18 |
Source: John S. Herold Database
Note: All data as of December 31, 2001, 2002, and 2003.
(Slide 25)
Ranger Anticline
This slide contains a vertical cross-section of the Ranger Anticline area with shading to denote upper and lower borum.
| * Thrust faulted/anticlinal Atokan sand play. |
| |
| * Repeat sections of tight gas sands. |
| |
| * Natural fractures enhance productivity. |
(Slide 26)
Focused on Adding Value
| Overton Well | | Ranger Well |
| Typical First Year Economics: | | | | | | |
Gross reserves (Bcfe) | 2.2 | 1.8 | 1.6 | | 1.8 | 1.2 |
| | (per Mcfe) | | (per Mcf) |
| Revenues | $5.00 | $5.00 | $5.00 | | $5.00 | $5.00 |
Production costs | $0.32 | $0.35 | $0.37 | | $0.20 | $0.25 |
Cash netback | $4.68 | $4.65 | $4.63 | | $4.80 | $4.75 |
F&D costs | $0.85 | $1.06 | $1.18 | | $0.80 | $1.20 |
| | | | | | |
| Total Life Economics: | | | | | | |
Completed Well Cost ($MM) | $1.5 | $1.5 | $1.5 | | $1.0 | $1.0 |
Pretax ROR | 55% | 30% | 25% | | 45% | 35% |
Pretax PVI | 2.3 | 1.7 | 1.5 | | 2.6 | 1.9 |
Note: Our ability to achieve our target PVI results are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and crude oil and our ability to add reserves at an acceptable cost.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 27)
U.S. Gas Consumption and Sources
This slide displays U.S. gas production versus U.S. gas consumption from 1975 to the present. Net gas imports for the same period are also given. U.S. gas production has been basically flat since 1994.
Source: EIA
(Slide 28)
U.S. Gas Production Decline Rate
This graph portrays U.S. natural gas production history. The graph indicates a 30% 2005 decline rate.
| | Production Decline Rate of Base |
1990 | | 17% | |
1991 | | 17% | |
1992 | | 16% | |
1993 | | 18% | |
1994 | | 19% | |
1995 | | 19% | |
1996 | | 20% | |
1997 | | 21% | |
1998 | | 23% | |
1999 | | 23% | |
2000 | | 25% | |
2001E | | 24% | |
2002E | | 27% | |
2003E | | 28% | |
| 2004E | | 29% | |
| 2005E | | 30% | |
Utilizes data supplied by IHS Energy; Copyright 1990 - 2004 IHS Energy
Chart prepared by and property of EOG Resources, Inc.; Copyright 2002 - 2004
(Slide 29)
U.S. Electricity Consumption on the Rise
This line graph shows an increase in U.S. electricity consumption in billion kilowatt-hours per month from 1990 to 2004.
Source: Edison Electric Institute
(Slide 30)
NYMEX Gas Prices
This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2004.
Source: Bloomberg
(Slide 31)
U.S. Gas Drilling
This line graph denotes the number of rigs drilling for gas through the period 1988 to 2004.
Source: Baker Hughes
(Slide 32)
West Texas Intermediate Oil Prices
This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2004.
Source: Bloomberg
(Slide 33)
Oil and Gas Price Comparison
This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl respectively for the period 1994 to 2004.
Source: Bloomberg
(Slide 34)
Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow
Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance 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. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misleading. Therefore, the reconciliation of the company's forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities. The first table below reconciles actual net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.
| 3 Months Ended June 30, | | 6 Months Ended June 30, |
| 2004 | | 2003 | | 2004 | | 2003 |
| (in thousands) |
Net Cash provided by operating activities | $43,733 | | $31,736 | | $120,473 | | $70,308 |
Add back (deduct): | | | | | | | |
Change in operating assets and liabilities | 6,570 | | (3,208) | | (13,651) | | (5,094) |
Net cash provided by operating activities before changes in operating assets and liabilities | | | | | | | |
| 2004 Guidance |
| NYMEX Commodity Price Assumptions |
| $5.00 Gas | | $6.00 Gas |
| $30.00 Oil | | $34.00 Oil |
| (in millions) |
Net cash provided by operating activities | $190-$193 | | $225-$228 |
Add back (deduct): | | | |
Change in operating assets and liabilities | -- | | -- |
Net cash provided by operating activities before changes in operating assets and liabilities | $190-$193 | | $225-$228 |
(Slide 35)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles 2004 forecasted EBITDA with 2004 forecasted net income.
| 12 Months Ended December 31, |
| 2003 | | 2002 | | 2001 | | 2000 | |
| | | | | | | | | |
Net income | $48,897 | | $14,311 | | $35,324 | | $20,461 | (1) |
Depreciation, depletion and amortization(2) | 57,762 | | 55,352 | | 53,641 | | 46,622 | |
Net interest expense | 17,311 | | 21,466 | | 23,699 | | 24,689 | |
Provision for income taxes | 28,372 | (3) | 8,708 | | 21,917 | | 11,457 | |
EBITDA | $152,342 | | $99,837 | | $134,581 | | $103,229 | (1) |
(1) 2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.
(2) Depreciation, depletion and amortization includes the amortization of restricted stock issued under the company's incentive compensation plan.
(3) Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.
The table below reconciles EBITDA with net income assuming different NYMEX price scenarios and their corresponding estimated impact on the company's results for 2004, including current hedges in place, as of July 30, 2004:
| | |
| | NYMEX Commodity Price Assumptions |
| | $5.00 Gas | | $6.00 Gas |
| | $30.00 Oil | | $34.00 Oil |
| ($ in millions) |
Net income | $72 - $75 | | $94 - $97 |
Add back: | | | |
Provision for income taxes - deferred | 44 - 45 | | 58 - 59 |
Interest expense | 17 - 19 | | 17 - 19 |
Depreciation, depletion, amortization | 73 - 75 | | 73 - 75 |
EBITDA | $207 - $210 | | $242 - $245 |
