Exhibit 99.1
Slide Presentation dated March 12, 2003
Slide presentation accompanying the March 12, 2003 presentation to investors during the Annual Global Energy Conference sponsored by CIBC World Markets, Inc. at the Millennium Broadway Hotel in New York.
(slide 1)
Southwestern Energy Company
CIBC World Markets
Annual Global Energy Conference
March 12, 2003
NYSE: SWN
[Picture of lock and skeleton key in weathered door. Key has keychain attached with the Company's formula inscribed.]
(slide 2)
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 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, 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 3)
About Southwestern
Focused on domestic production of natural gas. | ||
- | 415.3 Bcfe of reserves; 90% natural gas; 10.4 R/P. | |
Strategy built on organic growth through the drillbit. | ||
- | Low-risk development balanced with high-potential exploration. | |
Track record of adding significant reserves at low costs. | ||
- | Since 1999, we've averaged production growth of 7% per year, 197% reserve replacement, F&D cost of $1.07 per Mcfe. | |
Recent successful follow-on equity offering to accelerate development drilling at Overton Field. |
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 4)
About Southwestern
[Map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico with the following E&P operating areas identified: Arkoma Basin in western Arkansas and eastern Oklahoma; Permian Basin in Southeast New Mexico and West Texas; Gulf Coast in gulf coast regions of Louisiana and Texas; and East Texas in eastern Texas; Company's utility pipeline operations shown in northern Arkansas; Ozark Pipeline shown stretching from eastern Oklahoma into and across northern Arkansas.]
[Legend indicating gas distribution pipelines from Ozark Pipeline.]
[Textboxes shown which describe characteristics of the Company's two major business segments.]
E&P Segment
2002 Reserves: 415.3 Bcfe
90% Natural Gas
2002 Production: 40.1 Bcfe (1)
Reserve Life: 10.4 years
(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.
Utility Segment
140,000 customers in N. Arkansas
Territory includes 6th fastest growing region in U.S.
Filed rate case in November 2002
[Flags pointing to operating areas that indicate basin characteristics.]
Arkoma | ||
Reserves - 188.7 Bcf (45%) | ||
Production - 19.8 Bcf (49%) | ||
Permian | ||
Reserves - 57.1 Bcfe (14%) | ||
Production - 6.9 Bcfe (17%) (1) | ||
(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002. | ||
Gulf Coast | ||
Reserves - 58.5 Bcfe (14%) | ||
Production - 7.5 Bcfe (19%) | ||
East Texas | ||
Reserves - 111.0 Bcfe (27%) | ||
Production - 5.9 Bcfe (15%) |
(slide 5)
Proven Track Record
For the Periods Ended December 31,
1999 | 2000 | 2001 | 2002 | ||||||
Production (Bcfe) | 32.9 | 35.7 | 39.8 | 40.1 | |||||
Reserve Replacement | 150% | 196% | 224% | 209% | |||||
Reserve Additions (Bcfe) | 49.3 | 70.1 | 89.3 | 83.7 | |||||
F&D Cost ($/Mcfe) | $1.20 | $0.99 | $1.11 | $10.2 | |||||
Note: Reserve data excludes reserve revisions.
(slide 6)
Capital Investments
[bar chart showing Southwestern Energy Company's capital investments by general business activities.]
2000 | $75.7 |
2001 | $92.5 (1) |
2002 | $92.1 |
2003 Budget | $145.6 |
(1) Net of $13.5 million reimbursement from Overton Field partnership.
[pie chart showing Southwestern Energy Company's capital investments by areas of operation.]
East Texas | 53% |
Arkoma | 16% |
Gulf Coast | 15% |
Permian | 3% |
Other E&P | 7% |
Utility | 6% |
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 7)
Overton Field - An Impact Project
[locator map showing Smith County, Texas; map showing Overton Field area containing 16,500 acres with producing well locations, adjacent to South Overton Farm-in Acreage area of 5,800 acres with producing well locations; legend to map indicating existing wells at year-end 2002; textbox indicating information on this slide constitutes a "forward-looking statement;" textbox indicating Overton development potential as follows:]
Well Count | Approx. Spacing (Acres) | Reserve Potential (Net Bcfe) | |
Original Wells | 16 | 640 | 22 |
2001 Development | 15 | 400 | 36 |
2002 Development | 18 | 250 | 53 |
(slide 8)
Overton Field - An Impact Project
[locator map showing Smith County, Texas; map showing Overton Field area containing 16,500 acres with producing well locations and future development drilling locations, adjacent to South Overton Farm-in Acreage area of 5,800 acres with producing well locations and future development drilling locations; legend to map indicating existing wells at year-end 2002 and development locations for 2003-2004; textbox indicating information on this slide constitutes a "forward-looking statement;" textbox indicating Overton development potential as follows:]
Well Count | Approx. Spacing (Acres) | Reserve Potential (Net Bcfe) | |
Original Wells | 16 | 640 | 22 |
2001 Development | 15 | 400 | 36 |
2002 Development | 18 | 250 | 53 |
2003 Proposed Development | 47 | 120* | 83* |
2004 Proposed Development | 53 | 80* | 85* |
Total | 149 | 80* | 279 |
* In higher potential areas.
(slide 9)
Current Overton Drilling 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 |
Results:
Completed Well Cost | Pretax ROR | Pretax PVI |
$1.5 MM (1) | 35% (2) | 1.9 (2) |
(1) Current completed well cost estimate.
(2) Assumes $4.00 per Mcf flat pricing and gross EUR of 2.2 Bcfe per well.
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 10)
Overton Field Gross Production
[graph showing Overton Field gross production rate, potential rate with accelerated drilling program, and estimated rate with 18 well per year program.]
Overton Net Production | |
Bcfe | |
2000 | 0.3 |
2001 | 2.3 |
2002 | 5.9 |
2003 Forecast (1) | 10 - 13 |
2004 Forecast (1) | 18 - 20 |
Total Wells | Dec-01 | Dec-02 | Dec-03 | Dec-04 |
18 Well Drilling Program | 31 | 49 | 67 | 85 |
Accelerated Drilling Program (1) | 31 | 49 | 96 | 149 |
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 11)
Overton Field - Improved Drilling Results
Drilling Days versus Depth
[graph showing the depth and drilling days. The average for Overton was 27 days in 2000 and 35 days in 2001. FINA's average drilling time was 55 days.]
Reduced drilling time by greater than 50%.
Increased initial production by 200%.
Gross EUR 2.2 Bcfe per well.
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 12)
Arkoma Basin
[map showing location of Arkoma Basin in Arkansas and Oklahoma, the Arkoma Basin Fairway, the Ranger Anticline Prospect and the Haileyville Prospect.]
Arkoma Basin
- 3-year average results
- Reserve replacement: 97%
- LOE Cost (incl. Taxes) ($/Mcf): $0.30
- F&D Cost ($/Mcf): $1.08
Ranger Anticline
- Success: 12/15 wells
- Net EUR: 14.5 Bcf
- F&D/Mcf: $.82
Haileyville
- Success: 16/24 wells
- Net EUR: 9.3 Bcf
- F&D/Mcf: $.82
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 13)Gulf Coast Exploration
[map showing location of the 3D seismic acquired or purchased in 2002, the existing 3D seismic, the Horeb, Havilah, Malone, North Grosbec, Gloria, Crowne Discoveries, Chenier (2) and Duck Lake seismic area.]
Gulf Coast | 3 - Year Avg. Results |
Reserve Replacement: | 246% |
LOE Cost (incl. Taxes) ($/Mcfe): | $0.65 |
F&D Cost ($/Mcfe) | $1.83 |
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 14)
Exploration Potential - 196 Net Bcfe
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| Gross Res. | Net Res. | |||||||||||
Spud | Working | Potential | Potential | |||||||||||
Prospect Name | Operator | Date | Interest | Depth | Objective | (Bcfe) | (Bcfe) | |||||||
Arkoma Basin | ||||||||||||||
Midway | SWN | 1Q 2003 | 60.0% | 11,400 | Atoka | 20.0 | 10.5 | |||||||
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Permian Basin |
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Birds of Prey | SWN | Drilling | 100.0% | 5,000 | Cherry Canyon | 6.0 | 5.0 | |||||||
S. Roepke | SWN | Completing | 50.5% | 8,100 | Devonian | 4.0 | 1.6 | |||||||
Gaucho Deep | Devon | 3Q 2003 | 25.0% | 15,000 | Devonian | 30.0 | 6.0 | |||||||
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Gulf Coast |
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Jericho | SWN | Dry | 35.0% | 14,300 | Frio | - | - | |||||||
Shiloh | SWN | Drilling | 75.0%(1) | 14,000 | Cris R | 164.0 | 92.3 | |||||||
Ben Nevis | SWN | 3Q 2003 | 50.0% | 12,900 | Miocene | 45.0 | 16.9 | |||||||
Duck Lake (3) | SWN | 3-4Q 2003 | 50.0% | 16,000 | Planulina | 95.0 | 35.6 | |||||||
N. Shiloh | SWN | 4Q 2003 | 75.0% | 13,500 | Planulina | 50.0 | 28.1 | |||||||
Total Reserve Potential | 414.0 | 196.0 |
(1) SWN's % share of drilling and completion costs is 62.5%.
[textbox indicating information on this slide constitutes a "forward-looking statement".]
(slide 15)
How Have We Been Doing?
[graph showing the company's results in PVI, F&D Cost and Reserve Replacement from 1997 to 2002.]
1997 | 1998 | 1999 | 2000 | 2001 | 2002 | |||||||
F&D Cost ($/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: All metrics calculated exclude reserve revisions.
- 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 16)
Unit Cost Comparison - SWN is Competitive
[bar chat showing SWN's unit cost versus a peer group.]
Magnum Hunter (1) | Cimarex (3) | St. Mary | Westport | Chesapeake (2) | XTO | Mean | Median | Southwestern (4) | |
Interest | $0.64 | $0.02 | $0.05 | $0.36 | $0.60 | $0.23 | $0.32 | $0.30 | $0.41 |
G&A | 0.22 | 0.22 | 0.22 | 0.18 | 0.12 | 0.22 | 0.20 | 0.22 | 0.32 |
Operating | 1.12 | 0.69 | 0.97 | 0.89 | 0.65 | 0.78 | 0.85 | 0.83 | 0.64 |
F&D | 4.48 | 3.79 | 2.03 | 1.69 | 1.35 | 1.01 | 2.39 | 1.86 | 0.99 |
Source: RBC Capital Market
Note: Income statement data for the LTM ended 9/30/02 unless otherwise indicated. Finding cost data includes revisions and is for the year ended 12/31/01.
(1) LTM income statement data pro forma for the acquisition of Prize Energy Corp. |
(2) LTM income statement data pro forma for the acquisition of Canaan Energy Company. |
(3) Due to insufficient disclosure, Cimarex Energy Co. drilling data is not pro forma for the merger and instead is historical data for Key Production Company, Inc. |
(4) Data for the year ended 12/31/02. |
(slide 17)
Outlook for 2003
Production Targets:
- 42 - 44 Bcfe in 2003 (estimated growth of 5% to 10%).
- 50 - 55 Bcfe in 2004 (estimated growth of 20% to 25%).
2002 Actual | 2003 Guidance NYMEX Commodity Price Assumptions | |||
$3.22 Gas (1) | $3.50 Gas | $4.25 Gas | $5.00 Gas | |
$25.27 Oil (1) | $2.00 Oil | $24.50 Oil | $28.00 Oil | |
Earnings | $14 MM | $25 MM | $35 MM | $48 MM |
EPS | $.55 | $.73 | $1.02 | $1.40 |
Operating Income | $47 MM | $62 MM | $78 MM | $98 MM |
Cash Flow | $80 MM | $101 MM | $118 MM | $138 MM |
EBITDA | $100 MM | $120 MM | $137 MM | $157 MM |
Note: Per share estimates for 2003 assume 34.2 million weighted average diluted shares outstanding (includes 9.5 million shares issued in follow-on offering assuming the full exercise of the underwriters' over-allotment option). Cash flow is before changes in working capital.
(1) The average realized prices for our gas and oil production, after the effect of commodity hedge losses and basis differentials, were $3.00 per Mcf and $21.02 per Bbl, respectively, in 2002.
[textbox indicating information on this slide constitutes a "forward-looking statement".]
In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Cash Flow from Operating Activities from the Company's Form 10-K for the year ended December 31, 2002 is hereby furnished:
Cash flow from operating activities | $78 MM | |||
Add: Changes in assets and liabilities | 2 MM | |||
Cash fow (as presented) | $80 MM |
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 the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined.
2002 | 2003 Guidance NYMEX | ||||||
Actual | Commodity Price Assumptions | ||||||
$3.22 Gas | $3.50 Gas | $4.25 Gas | $5.00 Gas | ||||
$25.27 Oil | $22.00 Oil | $24.50 Oil | $28.00 Oil | ||||
($ in millions) | |||||||
Net Income | $14 | $25 | $35 | $48 | |||
Deferred Income Taxes | 9 | 15 | 22 | 30 | |||
Interest Expense | 21 | 19 | 19 | 18 | |||
Depreciation, Depletion and Amortization | 56 | 61 | 61 | 61 | |||
EBITDA | $100 | $120 | $137 | $157 |
(slide 18)
Gas Hedges in Place Through 2004
[chart showing gas hedges in place by quarter for the years 2003 and 2004.]
Type | Hedged Volumes | Average Price per Mcf (or Floor / Ceiling) | Percent of Total Production Hedged | |
2003 | Swaps | 13.3Bcf | $3.47 | 30 - 35% |
Collars | 17.1Bcf | $3.26 / $5.05 | 40 - 45% | |
2004 | Swaps | 7.2 Bcf | $4.00 | 10 - 15% |
Collars | 18.0Bcf | $3.78 / $5.77 | 35 - 40% |
Note: Southwestern has approximately 340,000 barrels of oil hedged at a fixed WTI price of $26.58 per barrel in 2003.
(slide 19)
Summary of Follow-On Offering
Captures Overton value in a high commodity price environment.
- - PVI = 1.9 @ $4.00 gas price.
Accelerates production and reserve growth.
Improves balance sheet and financial flexibility.
- - Debt-to-capital ratio improves to 48.6% (pro forma) from 65.9% at 12/31/02.
Improves liquidity - 42 new institutional holders added.