EX-99 3 exhibit991.htm EXHIBIT 99.1 Slide Presentation dated May 14, 2003

EXHIBIT 99.1

Slide Presentation dated September 16, 2003


The following slides were presented September 16, 2003 to institutional investors and analysts at the RBC Capital Markets 2003 North American Energy and Power Conference held at the Houstonian Hotel, Club and Spa in Houston, Texas.

(Slide 1)
Southwestern Energy Company

Presentation to RBC Capital Markets 2003 North American Energy and Power Conference

September 16, 2003

NYSE: SWN

This slide contains a picture of a weathered door lock and key. The attached keychain is inscribed with the Company's strategic formula . This formula summarizes the Company's belief that the right people doing the right things, wisely investing the cash flow from the underlying assets will create value +.

(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 $1.30 to $1.50 in discounted value for every dollar invested in a balanced exploration and production program in the Arkoma and Permian Basins, East Texas and the onshore Gulf Coast.

Market Data as of August 29, 2003

Shares of Common Stock Outstanding

35,575,442

Market Capitalization

$646,000,000

Institutional Ownership

81.0%

Management Ownership

7.3%

52-Week Price Range

$10.87 (10/18/2002)
 

$18.16 (08/29/2003)

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

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 4)

About Southwestern

The Company is focused on the domestic production of natural gas, with 90% of our 415.3 Bcfe of reserves being natural gas. The average life of those reserves is 10.4 years.

Our strategy is built upon a foundation of organic growth through the drillbit. This growth is balanced between low-risk development and high-potential exploration.

We have a proven track record of adding significant reserves at low costs. This can be shown in the fact that since 1999 we have averaged production growth of 7% per year, a 197% reserve replacement and a finding and development cost of $1.07 per Mcfe.

Southwestern Energy Company completed a follow-on equity offering in March 2003. This offering raised $103.2 million. These proceeds are being used to accelerate our development drilling in the Overton Field. They are also being used to reduce debt, improving our debt-to-capital ratio to 45% at 6/30/03 from 66% at 12/31/02.

Our Company has a strategy built around the formula . This formula summarizes our belief that the right people doing the right things, wisely investing the cash flow from the underlying assets will create value +.

(Slide 5)

Proven Track Record

This slide summarizes the Company's performance in four key indicators, production, reserve replacement, reserve additions and finding and development (F&D) cost. 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 6)

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.

E&P Segment

The Company's 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. Our E&P segment is comprised of four main areas, the Arkoma Basin, the East Texas Overton Field, the Gulf Coast and the Permian Basin. The reserve and production statistics, and the percentage of the whole for each area are as follows:

Arkoma

East Texas

Gulf Coast

Permian

Reserves (Bcfe)

188.7

111.0

58.5

57.1

% of Total Reserves

45%

27%

14%

14%

Production (Bcfe)

19.8

5.9

7.5

6.9

% of Total Production

49%

15%

19%

17% (1)

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

In the Arkoma Basin our strategy is to maintain our strong position through workovers and low-risk development drilling. Growth through low-risk infill drilling is our strategy in the East Texas Overton Field. We plan to focus on medium-risk exploration in the Permian Basin and high-potential exploration in the Gulf Coast region.

Utility Segment

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.

(Slide 7)

Capital Investments

This slide contains a bar chart that breaks the 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:

Utility &

Property

Capitalized

Leasehold

Development

Exploration

Corporate

Acquisitions

Expenses

& Seismic

Drilling

Drilling

($ in Millions)

2000

$6.5

$6.1

$9.7

$9.5

$23.7

$20.2

2001 (1)

$7.1

$0.7

$9.9

$9.8

$44.2

$20.8

2002

$6.9

$0.1

$10.9

$9.2

$46.3

$18.7

2003 Plan

$8.6

$2.3

$11.5

$15.8

$116.7

$18.7

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

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

 

 

% of Total

Capital Investments

East Texas

52%

Arkoma

19%

Gulf Coast

13%

Permian

4%

Other E&P

7%

Utility

5%

As the chart shows our E&P capital program is heavily weighted to low-risk drilling in 2003, with 52% or $90.2 million being spent in East Texas and 19% or $33.4 million being spent in the Arkoma Basin. The medium-risk Permian Basin has received 4% or $6.2 million of total capital investments, and the higher-risk, but larger potential Gulf Coast region received 13% or $22.7 million. Over 80% of the E&P capital has been allocated to drilling in 2003. The utility segment is very valuable in that it provides predictable earnings and cash flow.

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

(Slide 8)

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. The Company originally purchased 10,800 acres containing sixteen producing wells in 2000 for $6.1 million. The original wells were developed at 640-acre spacing. During 2001 and 2002 an additional 33 wells were drilled with 100% success. The three year average F&D cost for those wells is $0.63/Mcfe. The 2003-2004 drilling program contains plans to downspace to 80-acre spacing, creating 100 plus additional wells. Twenty-four wells were drilled in the first half of 2003. There is also the potential for further downspacing in the future. A summary of the Overton Field development potential is 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 (1)

97 (1)

2004 Proposed Development

53

80 (1)

85 (1)

Total

157

80 (1)

293

(1) In higher potential areas.

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

(Slide 9)

Overton 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 10)

Overton Field Gross Production

The graph contained in this slide displays the Overton Field gross production rate for the years 2000 to 2002. The potential gross production rate for 2003 and 2004 is also given under both an accelerated drilling program and under an eighteen well per year program.

The Overton Field's net production for the same years is 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 11)

Overton Field - Improved Drilling Results

This slide 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 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 12)

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. The 2003 capital program includes the drilling of 35 to 40 new wells in the Basin and the performance of 60 workovers. In addition, recent approval was given in the Ranger Anticline area to develop the field at 80-acre spacing.

The Arkoma Basin serves as a "legacy asset" for our Company. This area provides a stable production/reserve base and low-risk drilling opportunities with some upside exploration potential. In addition, our 60 years of experience in the Basin and our large acreage position of 385,000 gross acres and 263,000 net acres, provide us with a distinct competitive advantage over other producers.

Statistics for the entire 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 Prospect Results:

Success

17/20 wells

Net EUR

22.3 Bcf

F&D/Mcf

$.74

Haileyville Prospect Results:

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 13)

Ranger Anticline

This slide contains a map of the Ranger Anticline prospect. Our exploratory acreage and acreage held by production are designated with shading. Producing wells at 6/30/03 and 2003 proposed wells are also shown.

In early 2003, we received approval to downspace the Ranger Anticline field to 80 acres per well. We plan to drill fourteen wells in 2003 and have the potential for significant exploration and development drilling thereafter. We hold a large acreage position of 4,500 gross developed acres and 35,200 gross exploratory acres. Our average working interest in the area is 50% - 100%. A summary of the Ranger Anticline development potential is as follows:

   

Approx.

Reserve
 

Well

Spacing

Potential
 

Count

(Acres)

(Net Bcfe)

Producing Wells at 12/31/02

13

345

17

Wells Drilled in 1st Half of 2003

4

265

5

Remaining 2003 Development

10

165

11

Potential Future Locations

      

Development

13

110

12

Prob/Poss Locations

16

80

15

TOTAL

56

80

60

(Slide 14)

Gulf Coast Exploration

This map shows Company exploration activity within the Louisiana onshore Gulf Coast region. The Horeb, Havilah, Crowne, Cheniere (2), Duck Lake, North Grosbec, Gloria and Malone exploration areas in particular are highlighted. Shading denotes the areas where 3D seismic information either already existed or was acquired/purchased in 2002. Specifically, a license to over 1,000 square miles of 3-D shelf data was acquired in 2002. In addition, the 135-sqare mile Duck Lake 3-D project data is now in-house. Duck Lake is a highly prospective area in St. Martin and St. Mary Parishes where we are the operator and a 50% working interest owner. Drilling in the area is to commence in 2003.

The Gulf Coast map also points out areas of discovery and the locations of 2003 prospect wells. Out of the last nineteen wildcats drilled in South Louisiana we have produced eight discovery wells. Three-year average results for the 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 15)

Exploration Potential - 109 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

-

-

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

Drilling

12.5%

15,000

Devonian

30.0

3.0

Gulf Coast

              

Jericho

SWN

Dry

21.0%

14,300

Frio

-

-

Coleburn

SWN

3Q 2003

50.0%

13,000

Tex W

10.0

3.9

Canvasback

SWN

4Q 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

1Q 2004

50.0%

12,500

Siph D & Plan

49.4

18.5
     

Total Reserve Potential

295.2

108.9

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

(Slide 16)

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 has affected F&D Cost, Reserve Replacement and PVI.

1997

1998

1999

2000 (1)

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 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 17)

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 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.

 

Interest

G&A

Operating

F&D

Production(Bcfe)

Cimarex (1)

$0.01

$0.18

$0.57

$4.25

49.3

Magnum Hunter

$0.70

$0.21

$1.06

$2.21

43.8

St. Mary

$0.02

$0.23

$0.89

$1.53

54.0

Westport

$0.20

$0.17

$0.82

$1.40

91.3

Chesapeake

$0.62

$0.09

$0.65

$1.21

159.0

XTO

$0.34

$0.26

$0.87

$0.73

194.3

Mean

$0.32

$0.19

$0.81

$1.89

98.6

Median

$0.27

$0.20

$0.85

$1.47

72.6

Southwestern

$0.45

$0.33

$0.60

$1.17

38.5

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

(Slide 18)

Outlook for 2003

The Company has a targeted production of 42-44 Bcfe in 2003. This translates into an estimated growth rate of 5% to 10%. For the year 2004 the planned growth is 20% to 25%, or a production target of 50-55 Bcfe. Following are other key indicators under varying price assumptions.

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 19)

Gas Hedges in Place Through 2004

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

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%

Additionally, the Company has approximately 340,000 barrels of oil hedged at a fixed WTI price of $26.58 per barrel in 2003 and 120,000 barrels of oil hedged at a fixed WTI price of $27.25 per barrel in 2004.

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

(Slide 20)

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