EXHIBIT 99.1
Slide Presentation dated November 15, 2005
The following slides will be presented by Harold M. Korell, President and Chief Executive Officer of Southwestern Energy Company to investors at the 2005 Energy Conference sponsored by Bank of America in Boca Raton, Florida at the Boca Raton Resort & Club.
(Cover)
Southwestern Energy Company
November 2005 Update
NYSE: SWN
This left side of this slide contains a picture of an evergreen seedling. The caption below reads "New Things." The Company's formula
is located in the bottom center. The top right corner of this slide contains the company logo.
(Slide 1)
Southwestern Energy Company (NYSE: SWN)
General Information
Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering, transmission and marketing, and natural gas distribution.
Market Data as of November 8, 2005
Shares of Common Stock Outstanding | 83,531,593 |
Market Capitalization | $5,852,000,000 |
Institutional Ownership | 82.5% |
Management Ownership | 6.0% |
52-Week Price Range | $22.44 (1/5/05) |
$82.30 (10/3/05) |
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 2)
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 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, the extent of the company's success in drilling and completing horizontal wells, the company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation, lack of experience owning and operating drilling rigs, the timing and extent of the company's success in discovering, developing, producing and estimating reserves, property acquisition or divestiture activities, 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 (including regional basis differentials), 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, and any other factors listed in the reports filed by the company with the Securities and Exchange Commission (the "SEC"). For additional information with respect to certain of these and other factors, see reports filed by the company with the SEC. 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.
The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "estimated ultimate recovery," "EUR," "probable," "possible," and "non-proven" reserves, reserve "potential" or "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.
(Slide 3)
About Southwestern
| * Focused on domestic exploration and production of natural gas. | |
| * 645 Bcfe of reserves; 92% natural gas; 11.9 R/P at year-end 2004. | |
| * E&P strategy built on organic growth through the drillbit. | |
| * Over 80% of planned E&P capital allocated to drilling in 2005. | |
| * Track record of adding significant reserves at low costs. | |
* Since 1999, we've averaged annual production growth of 10%, reserve growth of 13%, 246% reserve replacement, and F&D cost of $1.28 per Mcfe. | |
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to over $5 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+. | |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 4)
Recent Developments
* Record Financial and Operating Results for First Nine Months of 2005. | |
* Production of 45.2 Bcfe, up 16%. | |
* Net income of $98.9 million, up 40%. | |
* Discretionary cash flow of $219 million, up 32%. | |
* 2005 full year production projected to be approximately 62 Bcfe, 15% growth from 2004. | |
* Operations Update | ||
* Overton and Ranger Anticline development programs delivering high-return growth. | ||
* Fayetteville Shale play - progress in horizontal drilling and confirmation of play. | ||
* Of the 67 wells drilled, 51 are now on production. | ||
* Recent successful follow-on equity offering to accelerate development of Fayetteville Shale play. |
* Increased 2005 capital budget to $499.5 million (up from original plan of $352.7 million). | |
* Includes $54.8 million for the purchase of ten new drilling rigs and related equipment (balance of $42.6 million due in 2006). | |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 5)
Proven Track Record
This slide contains bar charts for the periods ended December 31.
1999 | 2000 | 2001 | 2002 | 2003 | 2004 | 2005E | |
Production (Bcfe) | 32.9 | 35.7 | 39.8 | 40.1 | 41.2 | 54.1 | 62.0E |
Reserve Replacement | 150% | 196% | 224% | 209% | 351% | 388% | |
EBITDA ($MM)(1) | $76.1 | $103.2 | $134.6 | $99.8 | $152.3 | $256.4 | |
F&D Cost ($/Mcfe) | $1.20 | $0.99 | $1.11 | $1.02 | $1.18 | $1.34 |
Note: Reserve data excludes reserve revisions.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 33.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 6)
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) | ||
Burlington Resources | $0.59 | |
Houston Exploration | $0.62 | |
| Remington Oil & Gas | $0.62 | |
Southwestern Energy Company | $0.64 | |
Newfield Exploration | $0.74 | |
Pogo Producing Co. | $0.78 | |
EnCana | $0.80 | |
Chesapeake Energy | $0.80 | |
| Pioneer Natural Resources | $0.83 | |
Noble Energy | $0.84 | |
Range Resources | $0.85 | |
Cabot Oil & Gas | $0.85 | |
Apache | $0.92 | |
| Anadarko Petroleum | $0.94 | |
Devon Energy | $0.96 | |
XTO Energy | $0.99 | |
| Cimarex Energy | $1.00 | |
| Swift Energy | $1.03 | |
| St. Mary Land & Exploration | $1.13 | |
| Forest Oil | $1.18 | |
| Denbury Resources | $1.30 |
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 | $0.85 | |
Denbury Resources | $1.14 | |
| Burlington Resources | $1.19 | |
| Southwestern Energy Company | $1.21 | |
Noble Energy | $1.32 | |
Apache | $1.39 | |
Range Resources | $1.43 | |
Anadarko Petroleum | $1.47 | |
| Cabot Oil & Gas | $1.58 | |
EnCana | $1.61 | |
Swift Energy | $1.98 | |
| Houston Exploration | $1.98 | |
Chesapeake Energy | $2.17 | |
St. Mary Land & Exploration | $2.19 | |
| Remington Oil & Gas | $2.22 | |
| Devon Energy | $2.45 | |
Cimarex Energy | $3.09 | |
Newfield Exploration | $3.44 | |
| Pioneer Natural Resources | $3.58 | |
| Pogo Producing Co. | $3.70 | |
| Forest Oil | $3.97 |
Source: John S. Herold Database
Note: All data as of December 31, 2002, 2003, and 2004.
(Slide 7)
About the Company
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote the Arkoma and Permian Basins, the Gulf Coast and the East Texas regions. Lines trace gas distribution pipelines and the Ozark Pipeline.
Exploration & Production Segment
* 2004: 645 Bcfe of Reserves | |
| 92% Natural Gas |
| Production: 54.1 Bcfe | |
| * 2005 Est. Production: 62.0 Bcfe | |
Arkoma
* Reserves - 247.0 Bcf (38%) |
| * Production - 20.2 Bcf (37%) |
East Texas
* Reserves - 299.1 Bcfe (47%) |
* Production - 22.2 Bcfe (41%) |
Gulf Coast
* Reserves - 38.6 Bcfe (6%) |
* Production - 4.6 Bcfe (9%) |
Permian
* Reserves - 60.8 Bcfe (9%) |
* Production - 7.1 Bcfe (13%) |
Utility Segment
* 145,000 customers in N. Arkansas |
* Service area includes 6th fastest growing region in U.S. and the Milken Institute's 7th "Best Performing City" |
* Southwestern operates in Arkansas, Texas, New Mexico, Oklahoma and Louisiana and has three segments: E&P, Utility and Marketing. |
* E&P generates over 90% of operating income and EBITDA. |
* Utility and Marketing segments provide operating synergies for the E&P business in addition to contributing to the stability of our cash flow. |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 8)
Capital Expenditures
This slide contains a bar chart of Company capital investments, summarized as follows:
| 2006 | |||||
2005 | Preliminary | |||||
2002 | 2003 | 2004 | Plan | Plan | ||
| ($ in millions) | |||||
Utility & Other | $6.9 | $9.3 | $13.0 | $13.7 | $13.7 | |
Property Acquisitions | $0.1 | $ - | $14.2 | $0.0 | $0.0 | |
Cap. Exp. & Other | $10.9 | $12.4 | $17.9 | $35.3 | $45.7 | |
Leasehold & Seismic | $9.2 | $19.0 | $21.1 | $49.0 | $61.5 | |
Development Drilling | $46.3 | $119.7 | $208.7 | $307.0 | $455.2 | |
Exploration Drilling | $18.7 | $19.8 | $20.1 | $24.0 | $25.0 | |
| Midstream Services | $0.0 | $0.0 | $0.0 | $15.7 | $37.2 | |
| Rig Commitment | $0.0 | $0.0 | $0.0 | $54.8 | $42.6 | |
Total | $92.1 | $180.2 | $295.0 | $499.5 | $680.9 | |
This slide also contains a pie chart of Company's preliminary planned 2006 capital expenditures by area of operation, summarized as follows:
% of Total | |
Capital Investments | |
Arkoma Fayetteville Shale | 43% |
East Texas | 23% |
Arkoma | 12% |
| Drilling Rigs | 6% |
| Midstream | 5% |
| Other E&P | 5% |
Permian/Gulf Coast | 4% |
Utility | 2% |
* E&P capital program heavily weighted to low-risk drilling in 2005 and 2006. | |
|
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* Over 80% of E&P capital is expected to be allocated to drilling in 2005 and 2006. | |
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* Plan to invest approximately $132 million in 2005 and approximately $294 million in 2006 in Fayetteville Shale play. | |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 9)
East Texas - Overton Field
This slide contains a map of Smith County, Texas where the Overton Field is located. Existing wells at year-end 2003 and 2004 and 2005 development well locations are denoted. It is stated that the Overton Field contains 24,400 acres and the South Overton Farm-in Acreage contains 5,800 acres.
* Purchased original 10,800 acres and 16 producing wells for $6.1 million in 2000 (developed at 640-acre spacing). |
|
* Drilled 228 wells from 2001 through September 30, 2005, with 100% success. |
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* Plan to drill 82 wells in 2005, a portion of which will be at 40-acre spacing. |
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 | |
2004 Development | 83 | 100 | 142 | |
| Planned 2005 Development | 82 | 70 | 97 | |
Potential Future Development | ||||
| Locations @ $7.00 Gas with PVI >1.3 | >90 | 60 | 80 | |
Overton Field 2002-2004 Avg Results:(1)
Reserve Replacement: |
| 681% |
LOE Cost (incl. Taxes) ($/Mcfe): | $0.47 | |
F&D Cost ($/Mcfe): | $0.99 |
(1) Including reserve revisions.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 10)
Overton Field Gross Production
The graph contained in this slide displays the Overton Field gross production rate (MMcfe/d) from the year 2000 to December 2004. Additionally, in early 2003, the graph indicates an accelerated drilling program resulting from an equity offering. In 2004, the graph indicates addition of a fifth rig and curtailment issues.
Overton Net Production:
Bcfe | |
2000 | 0.3 |
2001 | 2.3 |
2002 | 5.9 |
2003 | 13.6 |
2004 | 21.8 |
| 2005 Forecast | 26 - 28 |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 11)
Overton Field - Improved Drilling Results
This slide of drilling days versus depth portrays the improved drilling rate in the Overton Field since its purchase from Fina in 2001. Fina's average drilling rate was 55 days. Upon the Field's purchase in 2001 SWN decreased that rate to 35 days. It was further decreased to 27 days in 2002, 23 days in 2003 and 19 days in 2004. (1)
* Reduced drilling time by >50%. |
|
* Increased initial production by 200%. |
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* Increased gross reserves by 60% (avg. gross EUR of 2.0 Bcfe per well in 2004) |
(1) The company has achieved the same drilling time of 19 days for year-to-date 2005.
(Slide 12)
Arkoma Basin - Conventional
This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin. The Ranger Anticline and the area known as the Fairway are further noted.
* 60+ years of experience in the basin, large acreage position of 483,000 net acres. |
* 2005 capital program includes drilling approximately 70 wells, including over 40 wells in the company's growing Ranger Anticline area. |
Arkoma Basin 2002-2004 Avg Results:(1)
Reserve replacement: | 191% |
LOE Cost (incl. Taxes) ($/Mcf): | $0.43 |
F&D Cost ($/Mcf): | $0.93 |
Ranger Anticline (inception thru 12/31/04):(1)
Success: | 43/50 |
Net EUR: | 62.8 Bcf |
F&D/Mcf: | $0.72 |
(1) Including reserve revisions.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 13)
Ranger Anticline
This slide contains a map of the Ranger Anticline prospect with the Company's exploratory and held by production acreage designated with shading. Also shown are SWN's producing wells at 12/31/04, and 2005 proposed wells.
Ranger Anticline (inception thru 12/31/04):(1)
Success: | 43/50 |
Net EUR: | 62.8 Bcf |
F&D/Mcf: | $0.72 |
* In July 2004, received approval to downspace field to 560 feet between wells. |
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* Current acreage position of 11,500 gross developed acres and 51,800 gross exploratory acres. |
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* Average working interest 50% - 100%. |
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* Plan to drill over 40 wells in 2005. Through September 2005, we participated in 33 wells, of which 27 were productive, four were in progress and two were dry. |
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* Area has significant growth potential/inventory. |
Ranger Anticline Potential:
Reserve | ||
Well | Potential | |
Count | (Net Bcfe) | |
Sucessful Wells at 12/31/02 | 13 | 20 |
Successful Wells in 2003 | 10 | 12 |
Successful Wells in 2004 | 20 | 31 |
2005 Drilling Program | 44 | 40 |
2006/2007 Potential Locations | 195 | 100 |
(1) Including reserve revisions.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 14)
Fayetteville Shale Play
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.
* Mississippian-age shale, geological equivalent of the Caney Shale in Oklahoma and the Barnett Shale in north Texas.
* 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.
* Currently hold approximately 849,000 net acres in the Fayetteville Shale play area (equivalent to over 1,300 square miles).
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 15)
Fayetteville Shale Focus Area
This slide contains a map of the Fayetteville Shale in Arkansas. The focus Area and existing pilot wells are indicated. The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Gravel Hill Field, Cove Creek Field and two wells new at 3rd quarter are also designated.
* To date, we have drilled 67 wells in ten separate pilot areas in five counties. |
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* AOGC has approved field rules for four pilot areas. Current field rules provide for 560 feet minimum distance between completions, up to a maximum of 25 wells per square mile (640 acres). |
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* We anticipate drilling 60 to 70 wells in 2005 (including 35 to 40 horizontal wells) and 175 to 200 wells in 2006, with the vast majority being horizontal. |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 16)
Focus on Horizontal Wells
Results to date indicate that optimal development of the resource will primarily require horizontal wells.
* Eighteen of the 67 wells drilled to date are horizontal wells. |
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* The average initial gross test rate for the 12 completed horizontal wells is 2.5 MMcf/d, excluding our first horizontal well in which problems with well bore isolation limited the stimulation treatment. |
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* Production data and modeling indicate that the average ultimate gross production from these horizontal wells will be between 1.3 and 1.7 Bcf per well. |
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* Costs of recently completed wells range from $1.4 to $1.8 million per well with an average vertical depth of 3,100 feet and average lateral length of 2,100 feet. |
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* Expected drainage from horizontal wells is currently estimated to be less than 80 acres per well. |
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 17)
How Have We Been Doing?
Graph shows F&D cost ($/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 | 2004 | |
F&D cost ($/Mcfe) | $2.53 | $1.10 | $1.20 | $.99 | $1.11 | $1.02 | $1.18 | $1.34 |
Reserve replacement (%) | 77% | 129% | 150% | 196% | 224% | 209% | 351% | 388% |
PVI ($/$) | $ .56 | $1.17 | $1.07 | $1.30 | $1.40 | $1.33 | $1.42 | $1.40 |
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 18)
Outlook
| * Production target of 62.0 Bcfe in 2005 (15% growth from 2004). |
| * 2005 guidance updated as of November 9, 2005 and reflects 2-for-1 split effective November 17, 2005. |
2004 Actual | 2005 Projected | |
$6.14 Gas | NYMEX/WTI | |
$41.36 Oil | Strip Case | |
Net Income | $103.6 MM | $141 - $151 MM |
EPS | $0.70 | $0.90 - $0.97 |
Operating Income | $182.3 MM | $244 - $254 MM |
Net Cash Flow(1) | $237.7 MM | $325 - $335 MM |
EBITDA(1) | $256.4 MM | $345 - $355 MM |
| CapEx | $295.0 MM | $499.5 MM |
Note: Guidance updated as of November 9, 2005. Diluted earnings per share for 2004 has been adjusted to give effect to the 2-for-1 stock split that occurred on June 3, 2005 and to reflect the company's 2-for-1 stock split effective November 17, 2005. 2005 guidance assumes approximately 155.3 million weighted average shares outstanding to give effect to the 2-for-1 stock split that occurred on June 3, 2005 and to reflect the company's 2-for-1 stock split effective November 17, 2005. 2004 oil and gas prices represent actual last-day NYMEX closing prices. 2005 oil and gas prices represent actual through November 2005 and assumes NYMEX/WTI strip prices as of November 4, 2005 for December 2005.
(1) Net Cash Flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 32 and 33.
Note that the information contained on this slide constitutes a "forward-looking statement".
(Slide 19)
The Road to V+
| * Invest in the Highest PVI Projects. | |
| * Accelerate Fayetteville Shale Development. | |
| * Accelerate Ranger Anticline Development. | |
| * Maximize Cash Flow. | |
| * Deliver the Numbers. | |
| * Production and Reserve Growth. | |
| * Add Value for Every Dollar Invested. | |
| * Continue to Tell Our Story. | |
(Slide 20)
Appendix
(Slide 21)
Financial & Operational Summary
This slide contains a table that summarizes the Company's financial and operational indicators.
| Nine Months Ended September 30, | Year Ended December 31, | |||||
| 2005 | 2004 | 2004 | 2003 | 2002 | ||
| ($ in millions, except per share amounts or as indicated) | ||||||
Revenues | $455.6 | $327.6 | $477.1 | $327.4 | $261.5 | |
EBITDA(1) | 241.4 | 179.0 | 256.4 | 152.3 | 99.8 | |
Net Income | 98.9 | 70.7 | 103.6 | 48.9 | 14.3 | |
Net Cash Flow(1) | 219.0 | 165.4 | 237.7 | 132.3 | 79.8 | |
Diluted EPS(2) | $0.65 | $0.48 | $0.70 | $0.36 | $0.14 | |
| Diluted CFPS(2) | $1.45 | $1.12 | $1.61 | $0.97 | $0.77 | |
| Production (Bcfe) | 45.2 | 39.0 | 54.1 | 41.2 | 40.1 | |
Avg. Gas Price ($/Mcf) | $6.16 | $5.07 | $5.21 | $4.20 | $3.00 | |
Avg. Oil Price ($/Bbl) | $42.29 | $29.51 | $31.47 | $26.72 | $21.02 | |
Finding Cost ($/Mcfe)(3) | $1.34 | $1.18 | $1.02 | |||
Reserve Replacement (%)(3) | 388% | 351% | 209% | |||
(1) 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 32 and 33.
(2) Diluted earnings per share and diluted cash flow per share have been adjusted to give effect to the 2-for-1 stock split that occurred on June 3, 2005 and to reflect the company's 2-for-1 stock split effective November 17, 2005..
(3) Excluding reserve revisions.
(Slide 22)
Gas Hedges in Place Through 2007
This slide contains a bar chart detailing gas hedges in place by quarter for the years 2005, 2006 and 2007. A summary of these outstanding gas hedges is as follows:
Average Price per Mcf | Percent | |||
Type | Hedged Volumes | (or Floor/Ceiling) | Hedged | |
2005 | Swaps | 12.6 Bcf | $5.04 | 20 - 25% |
Collars | 32.0 Bcf | $4.65 / $8.29 | 50 - 55% | |
2006 | Swaps | 7.0 Bcf | $6.27 | - |
Collars | 42.0 Bcf | $5.36 / $9.87 | - | |
2007 | Swaps | 12.0 Bcf | $6.66 | - |
Collars | 26.0 Bcf | $6.46 / $11.10 | - |
Note: Southwestern has approximately 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 23)
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 24)
Focused on Adding Value
Overton Well | Ranger Well | |||||
| Typical First Year Economics: | ||||||
Gross reserves (Bcfe) | 2.2 | 2.0 | 1.5 | 1.8 | 1.2 | |
| (per Mcfe) | (per Mcf) | |||||
| Revenues | $5.00 | $5.00 | $5.00 | $5.00 | $5.00 | |
Production costs | $0.38 | $0.40 | $0.45 | $0.28 | $0.36 | |
Cash netback | $4.62 | $4.60 | $4.55 | $4.72 | $4.64 | |
F&D costs | $0.90 | $1.01 | $1.34 | $0.80 | $1.20 | |
| ||||||
| Total Life Economics: | ||||||
Completed Well Cost ($MM) | $1.6 | $1.6 | $1.6 | $1.0 | $1.0 | |
Pretax ROR | 42% | 34% | 20% | 53% | 28% | |
Pretax PVI | 2.0 | 1.8 | 1.3 | 2.5 | 1.6 | |
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 25)
U.S. Gas Consumption and Sources
This slide displays U.S. gas production versus U.S. gas consumption from 1975 to the present. Net imports for the same period are also given. U.S. gas production has been basically flat since 1994.
Source: EIA
(Slide 26)
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 - 2005 IHS Energy
Chart prepared by and property of EOG Resources, Inc.; Copyright 2002 - 2005
(Slide 27)
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 2005.
Source: Edison Electric Institute
(Slide 28)
NYMEX Gas Prices
This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2005.
Source: Bloomberg
(Slide 29)
U.S. Gas Drilling
This line graph denotes the number of rigs drilling for gas through the period 1988 to 2005.
Source: Baker Hughes
(Slide 30)
West Texas Intermediate Oil Prices
This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2005.
Source: Bloomberg
(Slide 31)
Oil and Gas Price Comparison
This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1994 to 2005.
Source: Bloomberg
(Slide 32)
Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow
Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misleading. Therefore, the reconciliation of the company's forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities. The first table below reconciles actual net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.
| 9 Months Ended September 30, | 12 Months Ended December 31, | ||||||||
2005 | 2004 | 2004 | 2003 | 2002 | |||||
($ in thousands) | |||||||||
Net Cash provided by operating activities before changes in operating assets and liabilities | $219,003 | $165,345 | $237,706 | $132,327 | $79,775 | ||||
Add back (deduct): | |||||||||
Change in operating assets and liabilities | (3,181) | 17,974 | 191 | (23,228) | (2,201) | ||||
Net cash provided by operating activities | $215,822 | $183,319 | $237,897 | $109,099 | $77,574 | ||||
| 2005 Guidance |
| NYMEX Commodities Price Assumptions | |
| NYMEX/ |
| WTI Strip(1) |
Net cash provided by operating activities | $325-$335 |
Add back (deduct): | |
Assumed change in operating assets and liabilities | -- |
Net cash provided by operating activities before changes in operating assets and liabilities | $325-$335 |
(1) Projections use actual NYMEX prices through November 2005 and assume NYMEX closing price as of 11-4-05.
(Slide 33)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.
| 9 Months Ended September 30, | 12 Months Ended December 31, | ||||||||||||||
| 2005 | 2004 | 2004 | 2003 | 2002 | 2001 | 2000 | 1999 | ||||||||
| ($ in thousands) | ||||||||||||||
Net income | $98,904 | $70,661 | $103,576 | $48,897 | $14,311 | $35,324 | $20,461 | (1) | $9,927 | ||||||
Depreciation, depletion and amortization(2) | 71,021 | 54,334 | 76,065 | 57,762 | 55,352 | 53,641 | 46,622 | 42,387 | |||||||
Net interest expense | 13,904 | 12,544 | 16,992 | 17,311 | 21,466 | 23,699 | 24,689 | 17,351 | |||||||
Provision for income taxes | 57,541 | 41,499 | 59,778 | 28,372 | (3) | 8,708 | 21,917 | 11,457 | 6,449 | ||||||
EBITDA | $241,370 | $179,038 | $256,411 | $152,342 | $99,837 | $134,581 | $103,229 | (1) | $76,114 | ||||||
(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 2005 forecasted EBITDA with 2005 forecasted net income assuming different NYMEX price scenarios and their corresponding estimated impact on the company's results for 2005, including current hedges in place, as of November 9, 2005:
2005 Guidance | |
| NYMEX Commodity Price Assumptions | |
NYMEX/ | |
WTI Strip (2) | |
| (in millions) |
Net income | $141 - $151 |
Add back: | |
Provision for income taxes - deferred | 83 - 89 |
Interest expense | 18 - 19 |
Depreciation, depletion, amortization | 96 - 98 |
EBITDA | $345 - 355 |
(1) Projections use actual NYMEX prices through November 2005 and assume NYMEX closing prices as of 11-4-05.