EX-99.1 CHARTER 3 exhibit991.htm EXHIBIT 99.1 - SLIDE SHOW TRANSCRIPT Exhibit 99

Exhibit 99.1
Slide Presentation dated November 13, 2002

Slides prepared for use with November 13, 2002, presentation to investors at the Houstonian Hotel, Club and Spa in Houston, Texas during the RBC Capital Markets North American Energy Conference.

(slide 1)
Southwestern Energy Company
Presentation to RBC Capital Markets North American Energy Conference
November 13, 2002
[NYSE: SWN]

[picture of crescent and other wrenches.]

(slide 2)
Business Strategy
[slide stating formula which represents Company's strategy:  The Right People Doing the Right Things, supported by the value of underlying Assets will create Value+.]

(slide 3)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things.]

(slide 4)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things, wisely investing the cash flow from the underlying Assets.]

(slide 5)
[slide stating formula which represents Company's strategy emphasizing the Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+.]

(slide 6)
Southwestern Energy Company
[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; Anadarko Basin in North Texas and western Oklahoma, including the panhandle; 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.]

2001 Reserves: 402.0 Bcfe, 90% Gas
Shares Outstanding; 25.7 MM
52-Week Range: $9.64 - $15.19
Debt Ratings: BBB (S&P)
                     Ba2 (Moody's)

(slide7)
2001 Segment Contributions
[pie charts showing contribution from E&P, Gas Distribution, and Marketing & Other.]

 

Operating Income

Cash Flow

Assets

Capital Investments

Exploration & Production

84%

86%

71%

93%

Gas Distribution

12%

12%

23%

5%

Marketing & Other

4%

2%

6%

2%

Total

$57.8 MM

$112.7 MM

$743.1 MM

$106.1 MM

Note: Cash Flow is before changes in working capital.

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, 2001 is hereby furnished:

  Cash flow from operating activities    $144.6 MM  
  Less: Changes in assets and liabilities   

     31.9 MM

  
  Cash flow (as presented)     $112.7 MM  

(slide 8)
Cash Flow per Mcfe - SWN is Competitive
[graphs comparing Southwestern Energy Company's 3-year average Cash Flow per Mcfe of Production and Cash Flow per Mcfe of Reserves versus a peer group.]

Notes: All data as of December 31, 1999, 2000 and 2001. Cash Flow defied as Cash Flow from Operations before changes in working capital.
BR- Burlington Resources, CHK- Chesapeake Energy, COG - Cabot Oil & Gas, DVN - Devon Energy, EOG- EOG Resources, NFX - Newfield Exploration, NBL - Noble Affiliates, OEI - Ocean Energy, PXD- Pioneer Natural Resources, VPI - Vintage Petroleum, WRC - Westport Resources, XTO - XTO Energy.

(slide 9)
Key Developments - Organic Growth
1999
Positive E&P results.
        -        Reserve additions of 49 Bcfe replaced 150% of production at $1.20 per Mcfe.*
        -        First success in Gulf Coast exploration (Gloria).
        -        Developed excellent inventory of internally-generated exploration prospects.
2000
Strong E&P results.
        -        Reserve additions of 70 Bcfe replaced 196% of production at $0.99 per Mcfe.*
        -        Production increased over 8% from 1999 levels.
        -        Two meaningful discoveries in South Louisiana (N. Grosbec, Havilah).
Arkansas Supreme Court upheld jury verdict and judgment of $109 million.
2001
Record E&P results.
        -        Reserve additions of 89 Bcfe replaced 224% of production at $1.11 per Mcfe.*
        -        Production increased 11% from 2000 levels.
        -        Three exploration discoveries in South Louisiana (Malone, Horeb, Crowne).
Drilled 15 wells at Overton. Well performance exceeded expectations.
Reduced long-term debt by $46 million.

*Excludes reserve revisions.

(slide 10)
E&P Results - Standing Out
For the Periods Ended December 31,

 

1999

2000

2001

Production (Bcfe)

32.9  

35.7  

39.8  

Reserve Replacement

150%

196%

224%

Reserve Additions (Bcfe)

49.3  

70.1  

89.3  

F&D Cost ($/Mcfe)

$1.20

$0.99

$1.11

 

 

 

 

 

 

 

 

Note: Reserve data excludes reserve revisions.

(slide 11)
Objectives
Primary
Maximize the net present value of the enterprise.
        -        Invest in the highest PVI projects.
        -        In 2002, add $1.30 to $1.50 of discounted value for each dollar invested.
        -        Maximize cash flow to fund E&P program and pay down debt.

Secondary
Over a multi-year program, achieve 10% annual growth in production.
Reduce debt-to-total capital ratio over time to 50%.

(slide 12)
What is PVI?
PVI = Present Value Added per Dollar Invested
PVI = PV10 divided by Investment = PV10 ((Price * Mcfe) - (Cost * Mcfe)) divided by Investment

(slide 13)
E&P Assets and Strategy - Organic Growth
[map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico with the following areas identified: Mid-Continent in north Texas and western Oklahoma, including the panhandle; Arkoma in western Arkansas and eastern Oklahoma; Texas/New Mexico in southeast New Mexico and eastern, central and the gulf coast areas of Texas; South Louisiana in gulf coast region of Louisiana; and Overton in eastern Texas.]

Mid-Continent

Reserves - 36.6 Bcfe (9%)

Production - 2.8 Bcfe (7%)

Arkoma

Reserves - 186.0 Bcfe (46%)

Production - 22.3 Bcf (56%)

2002 Capital - $18.5 MM (23%)

Texas/New Mexico

Reserves - 79.4 Bcfe (20%)

Production - 7.6 Bcfe (19%)

2002 Capital - $9.5 MM (12%)

South Louisiana

Reserves - 42.4 Bcfe (11%)

Production - 4.8 Bcfe (12%)

2002 Capital - $21.2 MM (26%)

East Texas

Reserves - 57.6 Bcfe (14%)

Production - 2.3 Bcf (6%)

2002 Capital - $32.1 MM (39%)

(slide 14)
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: 96%
            LOE Cost (incl. Taxes) ($/Mcf): $0.26
            F&D Cost ($/Mcf): $1.05

Ranger Anticline
            Success: 10/14 wells
            Net EUR: 12.4 Bcf
            F&D/Mcf: $.69

Haileyville
            Success: 13/20 wells
            Net EUR: 9.7 Bcf
            F&D/Mcf: $.74

(slide 15)
Overton Field - Multi-Year Drilling Program
[map showing Overton Field area, including South Overton farm-in acreage of 5,800 acres, with producing well locations.]

 

Overton Field Drilling Potential

 

# Wells @ 80s

Net Reserve Potential

Year-End 2001

31

 58

2002 Drilling

18

   33*

Future Development

76

  137*

TOTAL

125

228

* Estimated gross reserves of 2.3 Bcfe per well.

Note: Excludes South Overton farm-in acreage.

Overton Field Gross Production Rate
[graph showing Overton Field gross production rate increasing from 1.7 MMcfe/d in June 2000 to over 20.0 MMcfe/d in August 2002.]

(slide 16)
South Louisiana 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.]

Recent Gulf Coast success: 8 successful wells out of last 14 drilled.
Current gross production from discoveries: 46 MMcfe per day (9 MMcfe per day net to SWN).
Exploration inventory with net reserve potential of 225 Bcfe through 2nd quarter of 2003.
Currently processing seismic data for Duck Lake 3-D project.

(slide 17)
Exploration Potential - 225 Net Bcfe

 

  

 

 

 

 

 

 

 

 

 

 

Gross Res.

 

Net Res.

  

   

 

 

Spud

 

Working

 

 

  

 

 

Potential

 

Potential

Prospect Name

  

Operator

 

Date

 

Interest

 

Depth

  

Objective

 

(Bcfe)

 

(Bcfe)

Arkoma Basin

  

 

  

 

 

 

 

 

  

 

 

 

 

 

Midway

  

SWN

 

4Q

 

60.0%

 

11,400

  

Atoka

 

39.0 

 

20.5 

 

  

 

 

 

 

 

 

 

  

 

 

 

 

 

Permian Basin

  

 

 

 

 

 

 

 

  

 

 

 

 

 

N. Roepke

  

SWN

  

Producing

 

88.0%

 

8,100

  

Devonian

 

3.0 

 

2.0 

Birds of Prey

  

SWN

 

Evaluating

 

100.0%

 

5,000

  

Cherry Canyon

 

6.0 

 

5.0 

High Lonesome

  

SWN

 

Prod/Eval

 

25.0%

  

11,000

  

Morrow

 

15.0 

 

3.0 

Gaucho Deep

  

Devon

 

1Q 2003

 

50.0%

  

15,000

  

Devonian

 

30.0 

 

12.0 

 

  

 

 

 

 

 

 

 

  

 

 

 

 

 

Gulf Coast

  

 

 

 

 

 

 

 

  

 

 

 

 

 

Crowne

  

SWN

 

Prod/Eval

 

40.0%

 

13,500

  

Planulina

 

35.0 

 

10.1 

Tulleymore

  

SWN

 

Dry

 

40.0%

 

12,500

 

Planulina

 

- 

 

- 

Bushmills

  

SWN

 

Dry

 

70.0%

 

15,200

 

Planulina

 

- 

 

- 

W. Grand Chenier

  

Ballard

  

Completing

 

25.7%

 

6,700

 

Big hum

 

2.0 

 

0.4 

Middle Chenier

  

Ballard

 

Completing

 

25.7%

 

13,500

 

Planulina

 

6.0 

 

1.1 

SE Grand Lake

  

Ballard

 

Dry

 

25.7%

 

14,000

 

Planulina

 

- 

 

- 

Little Chenier Bayou

  

Ballard

 

Drilling

 

25.7%

 

11,000

 

Siph D

 

35.0 

 

6.7 

W. Grand Chenier Deep

  

Ballard

  

4Q

 

25.7%

 

12,500

 

Siph D

 

40.0 

 

7.6 

Piedmont

  

SWN

 

Drilling

 

62.5%

 

13,300

 

Planulina

 

28.3 

 

14.0 

Jericho

  

SWN

 

1Q 2003

 

35.0%

 

14,200

 

Frio

 

72.0 

  

18.9 

Shiloh

  

SWN

  

1Q 2003

 

62.5%

 

13,500

 

Planulina

 

164.0 

 

79.9 

Ben Nevis

  

SWN

 

2Q 2003

 

50.0%

 

12,900

 

Miocene

 

45.0 

 

16.0 

Tigris

  

SWN

 

2Q 2003

 

50.0%

 

13,600

 

Frio

 

74.0 

 

27.8 

 

  

 

 

 

 

Total Reserve Potential

 

594.3 

 

224.9 

[textbox indicating information on this slide constitutes a "forward-looking statement".]

(slide 18)
E&P Capital Investments
[bar chart showing Southwestern Energy Company's capital investment by general business activities.]

1999

$59.0

2000

$69.2

2001

$85.5 (1)

2002 Budget

$81.3

(1) Net of $13.5 million reimbursement from Overton Field partnership.

[pie chart showing Southwestern Energy Company's capital investment by areas of operation.]

East Texas

39%

South Louisiana

26%

Arkoma

23%

Permian

12%

(slide 19)
Outlook for 2002
Targets:
        -        Production target of 40 - 41 Bcfe in 2002.
        -        Excess cash flow goes toward long-term debt reduction.

NYMEX Commodity Price Assumptions

$2.25 Gas

$3.00 Gas

$3.50 Gas

$3.75 Gas

$21.00 Oil

$21.00 Oil

$21.00 Oil

$21.00 Oil

              Earnings

$10 MM

$15 MM

$19 MM

$21 MM

              EPS

$.40

$.60

$.73

$.80

             Cash Flow

$76 MM

$85 MM

$91 MM

$95 MM

             CFPS

$3.00

$3.30

$3.50

$3.67

             EBITDA

$97 MM

$106 MM

$112 MM

$116 MM

[textbox indicating information on this slide constitutes a "forward-looking statement".]

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.

  $2.25 Gas  $3.00 Gas  $3.50 Gas  $3.75 Gas 
  $21.00 Oil  $21.00 Oil  $21.00 Oil  $21.00 Oil 
 

  ($ in millions)

Net Income

 $10  $15  $19  $21 

Deferred Income Taxes

 6  10  12  14 

Interest Expense

 22  22  22  22 

Depreciation, Depletion and Amortization

59 

59 

59 

59 

EBITDA

$97 

$106 

$112 

$116 

(slide 20)
Gas Hedges in Place Through 2003
[chart showing gas hedges in place by quarter for the years 2003 and 2004.]

 

Hedged Volumes

Average Floor Price

2002

28.0 Bcf

$3.10/Mcf

2003

27.4 Bcf

$3.28/Mcf

2004

7.2 Bcf

$3.58/Mcf

Note: Southwestern has approximately 280,000 barrels of oil hedged at a fixed WTI price of $20.07 per barrel in 2002 and 240,000 barrels of oil hedged at a fixed WTI price of $25.40 per barrel in 2003.

(slide 21)
The Right People Doing the Right Things
[graph showing the company's results in PVI, F&D Cost and Reserve Replacement from 1997 to 2001.]

Note: PVI metrics calculated using pricing in effect at year-end (except for 2000 which was calculated at $3.00 per Mcf natural gas price). All metrics calculated exclude reserve revisions.

1997

1998

1999

2000

2001

F&D Cost ($/Mcfe)

$2.53

$1.10

$1.20

$.99

$1.11

Reserve Replacement

77%

129%

150%

196%

224%

PVI ($/$)

$ .56

$1.17

$1.07

$1.30

$1.40

(slide 22)
The Road to V+
Invest in the Highest PVI Projects.
Maximize Cash Flow.
Stay the Course with Our Balanced Strategy.
Build on Exploration Success.
Reduce Debt with Excess Cash Flow.
Deliver the Numbers.
        -        Production and Reserve Growth.
        -        Add value for Every Dollar Invested.
Continue to Tell Our Story.

(slide 23)
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, legal and economic factors, governmental regulation, the financial impact of accounting regulations for derivative instruments, 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.

(slide 24)
Appendix

(slide 25)
Financial and Operational Summary

 

9 Months Ending September 30,

    Year Ended

 

2002

2001

2001

2000(1)

1999

                                                                   ($ in millions, except per share amounts)

Revenues

$188.8

$272.5

$344.9

$363.9

$280.4

EBITDA

74.9

103.4

134.9

103.8

76.7

Net Income

9.8

27.9

35.3

20.5

9.9

Cash Flow (2)

58.9

86.4

112.7

82.4

60.8

Diluted EPS

$0.37

$1.09

$1.38

$0.82

$0.40

Diluted CFPS

$2.26

$3.38

$4.40

$3.29

$2.44

 

 

 

 

 

 

Production (Bcfe)

30.6

29.3

39.8

35.7

32.9

Avg. Gas Price ($/Mcf)

$2.89

$3.97

$3.85

$2.88

$2.21

Avg. Oil Price ($/Bbl)

$20.87

$24.67

$23.55

$22.99

$17.11

 

 

 

 

 

 

Finding Cost ($/Mcfe) (3)

 

 

$1.11

$0.99

$1.20

Reserve Replacement (%) (3)

 

 

224%

196%

150%

(1)        Before the effects of unusual and extraordinary items.
(2)        Cash Flow is before changes in working capital.
(3)        Excluding reserve revisions.

In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Cash Flow from Operating Activities from the Company's Form 10-Q for the nine months ended September 30, 2002, and Form 10-K for the year ended December 31, 2001 is hereby furnished:

                       
   

9 Months Ending

            
   

September 30,

  

Year Ended
     

2002

  

2001

  

2001

  

2000(1)

  

1999
   

($in millions)
Cash flow from operating activities  

$68.4 

   $114.7    $144.6    $58.1    $58.1 
Less: Changes in assets and liabilities  

   9.5 

  

28.3 

  

31.9 

  

(24.3)

  

(2.7)
Cash flow (as presented)  

$58.9 

   $86.4    $112.7    $82.4    $60.8 
  (1) Before the effects of unusual and extraordinary items                  

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.

9 Months Ending

      
   

September 30,

  

Year Ended
     

2002

  

2001

  

2001

  

2000(1)

  

1999
   

($in millions)
Net Income  

$9.8 

   $27.9    $35.3    $20.5    $9.9 
Deferred Income Taxes   6.1    17.8     21.9    12.9    6.4 
Interest Expense   16.1    18.3    23.7    23.2    17.4 
Depreciation, Depletion and Amortization  

42.9 

  

39.4 

  

54.0 

  

47.2 

  

43.0 
EBITDA   $74.9    $103.4    $134.9    $103.8    $76.7 
           

(slide 26)
U.S. Gas Consumption and Sources
[graph showing U.S. gas consumption, U.S. gas production, and net imports in Bcf per year from 1975 to 2001; textbox indicating that U.S. gas production is basically flat since 1994.]
Source: EIA

(slide 27)
U.S. Electricity Consumption on the Rise
[graph showing an increase in U.S. electricity consumption in billion kilowatt hours per month from 1990 to 2002.]
Source: Edison Electric Institute

(slide 28)
NYMEX Gas Prices
[graph showing NYMEX gas prices in $/Mcf from 2000 through 2002.]
Source: Bloomberg

(slide 29)
U.S. Gas Drilling
[graph showing the number of rigs drilling for gas from 1988 through 2002.]
Source: Baker Hughes

(slide 30)
West Texas Intermediate Oil Prices
[graph showing intermediate oil prices in $/Bbl in West Texas from 2000 through 2002.]
Source: Bloomberg

(slide 31)
Oil and Gas Price Comparison
[graph comparing prices of Henry Hub natural gas and WTI crude oil from 1994 through 2002.]
Source: Bloomberg