EX-99 3 exhibit991.htm Slide Presentation dated May 14, 2003

EXHIBIT 99.1

Slide Presentation dated August 7, 2003


Slides were prepared for a presentation given August 7, 2003 to institutional investors and analysts at the 8th Annual Oil and Gas Conference held at the Pinnacle Club in Denver, Colorado.

(Slide 1)
Southwestern Energy Company

Presentation to the Oil and Gas Conference

August 7, 2003

NYSE: SWN
[Picture of a weathered door lock and key. A keychain inscribed with the Company's formula is attached.]

(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 have averaged production growth of 7% per year, 197% reserve replacement, and F&D cost of $1.07 per Mcfe.

Follow-on equity offering completed in March 2003. $103.2 million was raised with the proceeds being used to accelerate development drilling at Overton Field and to reduce debt. This offering decreased our debt-to-capital ratio from 66% at 12/31/02 to 45% at 6/30/03.

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)

Proven Track Record

Slide summarizes the Company's performance in four key indicators. Those indicators for the periods ended December 31 are as follows:

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

$1.02

Note: Reserve data excludes reserve revisions.

(Slide 5)

E&P Focused

Slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote areas of active E&P and lines to trace gas distribution pipelines and the Ozark Pipeline.

Our E&P segment had production in 2002 of 40.1 Bcfe (1). We had reserves of 415.3 Bcfe in 2002, 90% of which were natural gas. The average life of those reserves is 10.4 years. The Company's four operating areas, their reserve and production statistics, and their percentage of the whole are as follows:

Arkoma

East Texas

Gulf Coast

Permian

Reserves (Bcf)

188.7

111.0

58.5

57.1

% of Total Reserves

45%

27%

14%

14%

Production

19.8

5.9

7.5

6.9

% of Total Production

49%

15%

19%

17% (1)

The Company's utility segment services 140,000 customers in Northern Arkansas, a territory which includes the 6th fastest growing region in the U.S. according to the U.S. Census Bureau. In November 2002 we filed for an $11.0 million annual rate increase with the Arkansas Public Service Commission.

(1) Includes 2.0 Bcfe of production related to Mid-Continent properties sold during 2002.

(Slide 6)

Capital Investments

This slide contains a bar chart that breaks Southwestern Energy Company's capital investments down by general business activity, including utility and corporate, property acquisitions, capitalized expenses, leasehold and seismic, development drilling and exploration drilling. The summary of those investments is as follows:

$ Millions

2000

$75.7

2001

(1) $92.5

2002

$92.1

2003 Plan

$173.6

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

This slide also contains a pie chart showing capital investments by area of operation. The results are as follows:

 

East Texas

52%

Arkoma

19%

Gulf Coast

13%

Permian

4%

Other E&P

7%

Utility

5%

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 7)

Overton Field - An Impact Project

This slide contains a map of Smith County, Texas where the Overton Field production area is located. This area consists of 17,600 acres in the Overton Field and an additional 5,800 farm-in acres in the South Overton area. Existing wells at year-end 2002 and development locations for 2003-2004 are shown. Also given are statistics of the Overton development potential. They are as follows:

   

Approximate

Reserve
 

Well

Spacing

Potential
 

Count

(Acres)

(Net Bcfe)

Original Wells

16

640

22

2001 Development

15

400

36

2002 Development

18

250

53

2003 Proposed Development

55

120*

97*

2004 Proposed Development

53

80*

85*

Total

157

80*

293*

* In higher potential areas.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 8)

Current Overton Drilling Economics

Typical First Year Economics:

Revenues - $4.00 per Mcfe

Production costs - $0.30 per Mcfe

Cash netback - $3.70 per Mcfe

F&D costs - $0.85 per Mcfe

Total Life Economics:

Completed well cost - $1.5 MM (1)

Pretax ROR - 35% (2)

Pretax PVI - 1.9 (2)

  1. Current completed well cost estimate.

  2. Assumes $4.00 per Mcf flat pricing and gross EUR of 2.2 Bcfe per well.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 9)

Overton Field Gross Production

Slide contains a graph showing the Overton Field gross production rate for 2000 to 2002 and the potential rate for 2003 and 2004 under both an accelerated drilling program and under an 18 well per year program.

In addition, Overton's net production is given as follows:

Bcfe

2000

0.3

2001

2.3

2002

5.9

2003 Forecast (1)

10 - 13

2004 Forecast (1)

18 - 20

The total number of wells under the two given drilling program options are as follows:

Dec-01

Dec-02

Dec-03

Dec-04

18 Well Drilling Program

31

49

67

85

Accelerated Drilling Program (1)

31

49

104

157

  1. Assumes accelerated development of Overton with equity offering.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 10)

Overton Field - Improved Drilling Results

In this slide a graph is given portraying 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 we decreased that rate to 35 days. It was further decreased to 27 days in 2002 and 24 days in 2003. Thus, drilling time has been reduced by greater than 50% over the rate of previous owners. We also increased initial production by 200% and gross reserves by 60% to 2.2 Bcfe per well.

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 11)

Arkoma Basin

This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin production area. The Ranger Anticline and Haileyville prospects and the area known as the Fairway are further noted. Recent approval was given in the Ranger Anticline area to develop the field at 80-acre spacing.

Statistics for the Arkoma Basin, and the Haileyville and Ranger Anticline prospects are given as follows:

Arkoma Basin three year average results

Reserve replacement

97%

LOE cost (incl. Taxes) ($/Mcf)

$0.30

F&D cost ($/Mcf)

$1.08

Ranger Anticline

Success

17/20 wells

Net EUR

22.3 Bcf

F&D/Mcf

$.74

Haileyville

Success

16/24 wells

Net EUR

9.3 Bcf

F&D/Mcf

$.82

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 12)

Gulf Coast

This map highlights the areas within the onshore Gulf Coast region where Company 3D seismic information either already existed or was acquired or purchased in 2002. Specifically, the Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone seismic areas are noted.

Three-year average results for this region are as follows:

Reserve Replacement

246%

LOE Cost (incl. Taxes) ($/Mcfe)

$0.65

F&D Cost ($/Mcfe)

$1.83

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 13)

Exploration Potential - 224 Net Bcfe

This slide contains a table summarizing the exploration potential of the Company's production areas.

         

Unrisked Reserve
   

Spud

Working

  

Potential (Bcfe)

Prospect Name

Operator

Date

Interest

Depth

Objective

Gross

Net

Arkoma Basin

              

Midway

SWN

Dry

60.0%

11,400

Atoka

0

0

Permian Basin

              

Birds of Prey

SWN

Producing

100.0%

5,000

Cherry Canyon

14.8

11.8

S. Roepke

SWN

Producing

50.5%

8,100

Devonian

1.0

0.4

River Ridge

EGL

3Q 2003

12.5%

15,000

Devonian

30.0

3.0

Gulf Coast

              

Jericho

SWN

Dry

21.0%

14,300

Frio

0

0

Shiloh

SWN

T&A'd

100.0%

14,000

Cris R

164.0

98.2

Coleburn

SWN

3Q 2003

50.0%

12,700

Tex W

10.0

3.9

Ben Nevis

SWN

3Q 2003

50.0%

12,900

Miocene

45.0

16.9

Canvasback

SWN

3Q 2003

50.0%

18,200

Liebusella

80.0

30.0

Daffy

SWN

4Q 2003

50.0%

14,500

Siph D & Plan

110.0

41.3

Redhead

SWN

4Q 2003

50.0%

12,500

Siph D & Plan

49.4

18.5
     

Total Reserve Potential

504.2

224.0

Note that the information contained on this slide constitutes a "forward-looking statement".

(Slide 14)

How Have We Been Doing?

The graph contained on this slide shows how the implementation of a new management and E&P team along with a new strategy have affected F&D Cost, Reserve Replacement and PVI.

1997

1998

1999

2000

2001 (1)

2002

F&D cost ($/Mcfe)

$2.53

$1.10

$1.20

$.99

$1.11

$1.02

Reserve replacement

77%

129%

150%

196%

224%

209%

PVI ($/$)

$ .56

$1.17

$1.07

$1.30

$1.40

$1.33

Note that all metrics calculated exclude reserve revisions.

(1) PVI metrics were calculated using pricing in effect at year-end with exception to the year 2000 which was calculated at $3.00 per Mcf natural gas price.

(Slide 15)

Unit Cost Comparison - SWN is Competitive

The bar graph given in this slide compares various expenses of the Company to similar measurements of its competitors. The data given represents 2000-2002 three-year averages, with income statement data being for the years ended December 31 unless otherwise indicated. Finding cost data includes revisions.

Cimarex (1)

Magnum Hunter

St. Mary

Westport

Chesapeake

XTO

Mean

Median

Southwestern

Interest

$0.01

$0.70

$0.02

$0.20

$0.62

$0.34

$0.32

$0.27

$0.45

G&A

$0.18

$0.21

$0.23

$0.17

$0.09

$0.26

$0.19

$0.20

$0.33

Operating

$0.57

$1.06

$0.89

$0.82

$0.65

$0.87

$0.81

$0.85

$0.60

F&D

$4.25

$2.21

$1.53

$1.40

$1.21

$0.73

$1.89

$1.47

$1.17

(1) Cimarex Energy income statement data for the years 2000 and 2001 are for the year ended September 30.

(Slide 16)

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 Price Assumptions

$3.22 Gas (1)

$5.00 Gas

$6.00 Gas

$25.27 Oil (1)

$28.00 Oil

$28.00 Oil

Earnings

$14 MM

$43 - 46 MM

$55 - 58 MM

EPS

$.55

$1.25 - $1.35

$1.60 - $1.70

Operating Income

$47 MM

$90 - 93 MM

$109 - 112 MM

Cash Flow

$80 MM

$133 - 136 MM

$152 - 155 MM

EBITDA

$100 MM

$150 - 153 MM

$169 - 172 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). 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.

Note that the information contained on this slide constitutes a "forward-looking statement".

In accordance with Regulation G, a reconciliation of Cash Flow, as presented, to Net Cash Provided by Operating Activities from the Company's Form 10-K for the year ended December 31, 2002 is hereby furnished:

Net cash provided by operating activities

$78 MM

Add: Changes in operating assets and liabilities

$2 MM

Cash flow (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 Actual

2003 Guidance NYMEX Commodity Price Assumptions
 

$3.22 Gas

$5.00 Gas

$6.00 Gas
 

$25.27 Oil

$28.00 Oil

$28.00 Oil
 

($ in millions)

Net Income

14

43 - 46

55 - 58

Deferred Income Taxes

9

26 - 28

34 - 36

Interest Expense

21

17 - 19

17 - 19

Depreciation, Depletion and Amortization

56

60 - 62

60 - 62

EBITDA

100

150 - 153

169 - 172

(Slide 17)

Gas Hedges in Place Through 2004

This slide contains a bar chart showing gas hedges in place by quarter for the years 2003 and 2004.

     

Average Price per Mcf

Percent of Total
 

Type

Hedged Volumes

(or Floor/Ceiling)

Production Hedged

2003

Swaps

13.3 Bcf

$3.47

30 - 35%
 

Collars

17.1 Bcf

$3.26 / $5.05

40 - 45%

2004

Swaps

7.2 Bcf

$4.00

10 - 15%
 

Collars

22.0 Bcf

$3.82 / $6.26

40 - 45%

(Slide 18)

The Road to V+

This slide summarizes the strategy by which the Company plans to continue to create added value in everything it does.

Invest in the Highest PVI Projects

  
 

Accelerate Overton Development with Proceeds from Equity

 

Offering (PVI = 1.9 @ $4.00 Gas Price).

Maximize Cash Flow

  

Stay the Course with Our Balanced Strategy

  

Deliver the Numbers

  
 

Production and Reserve Growth
 

Add value for Every Dollar Invested

Continue to Tell Our Story

  

(Slide 19)

Appendix

(Slide 20)

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. As the chart shows, U.S. gas production has been basically flat since 1994.

Source: EIA

(Slide 21)

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 2003.

Source: Edison Electric Institute

(Slide 22)

NYMEX Gas Prices

This line graph represents NYMEX gas prices in $/Mcf from 2000 to 2003.

Source: Bloomberg

(Slide 23)

U.S. Gas Drilling

This line graph denotes the number of rigs drilling for gas through the period 1988 to 2003.

Source: Baker Hughes

(Slide 24)

West Texas Intermediate Oil Prices

This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to 2003.

Source: Bloomberg

(Slide 25)

Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu for the period 1994 to 2003.

Source: Bloomberg