Slide Presentation dated April 18, 2001
Slides prepared for use with April 18, 2001, presentation to investors at the
IPAA Oil and Gas Investment Symposium.
(slide 1)
Southwestern Energy Company
Presentation to IPAA Oil & Gas Investment Symposium
[NYSE: SWN]
[picture of drilling pipes]
(slide 2)
Southwestern Energy Company (NYSE: SWN)
General Information
Southwestern Energy Company is primarily focused on natural gas.
Southwestern's strategy is to add $1.50 to $1.90 in discounted value for every
dollar invested in a well-balanced exploration and production program in the
Arkoma and Permian basins, east Texas and the onshore Gulf Coast.
Market Data as of March 31, 2001
Shares of Common Stock Outstanding - 25,188,574
Market Capitalization - $250,000,000
Institutional Ownership - 69.0%
Management Ownership - 9.1%
52-Week Price Range - $6.13 (6/27/2000) - $11.05 (3/9/2001)
Investor Contacts
Greg D. Kerley
Executive Vice President and Chief Financial Officer
Phone: (281) 618-4803 Fax: (281) 618-4757
Brad D. Sylvester, CFA
Manager, Investor Relations
Phone: (501) 582-8497 Fax: (501) 521-0328
(slide 3)
Business Strategy
[slide stating formula which represents Company's strategy: The Right People
doing the Right Things, supported by the value of our underlying Assets will
create Value +.]
(slide 4)
Southwestern Energy Company
[map showing the states of Arkansas, Louisiana, Texas, Oklahoma and New Mexico
with the following areas identified: Arkoma Basin with the Company's Gas
distribution system and Ozark Pipeline, Anadarko Basin, Permian Basin, East
Texas Overton Field and Gulf Coast]
2000 Reserves: 380.5 Bcfe, 82% PDP
Shares Outstanding: 25.2 MM
52-Week Range: $6.13 - $11.05
(slide 5)
2000 Segment Contributions
[slide depicting business segment contributions in the following areas:]
Operating Income $57.8 MM
Exploration & Production 70%
Gas Distribution 25%
Marketing & Other 5%
Cash Flow $82.4 MM
Exploration & Production 77%
Gas Distribution 20%
Marketing & Other 3%
Assets $705.4 MM
Exploration & Production 65%
Gas Distribution 27%
Marketing & Other 8%
Capital Investments $75.7 MM
Exploration & Production 91%
Gas Distribution 8%
Marketing & Other 1%
Amounts and percentages exclude the effects of unusual and extraordinary items.
Cash flow is before changes in working captial.
(slide 6)
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.] For
E&P segment only, cash flow per Mcfe of production is $1.55 and cash flow per
Mcfe of reserves is $.15.
(slide 7)
Value Incongruity
[graph comparing Southwestern Energy Company's 3-year average Cash Flow per Mcfe
of Production versus a peer group plus a graph comparing Southwestern Energy
Company's Price-to-Cash Flow Multiple to a group of peers.]
Cash flow for E&P segment equals $1.55 per Mcfe.
Peer group average Price-to-Cash Flow Multiple is 5.0 times.
(slide 8)
Key Developments
1999
o 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.
o Sold Missouri utility assets for $32 million.
2000
o Supreme Court upheld jury verdict and judgment of $109 million.
o Strong E&P results.
>> Reserve additions of 70 Bcfe replaced 196% of production at $0.99 per Mcfe.
>> Production increased over 8% from 1999 levels.
>> Three meaningful discoveries in south Louisiana (North Grosbec, Havilah,
Malone).
(slide 9)
2000 Results ($ in millions)
For the Year Ended December 31, 2000
2000 1999
Operating Income $57.8 $36.1 +60%
Net Income $20.5 $9.9 +106%
Cash Flow $82.4 $60.8 +35%
Production (Bcfe) 35.7 32.9 +8%
Amounts and percentages exclude the effects of unusual and extraordinary items.
Cash flow is before changes in working capital.
(slide 10)
Objectives
Become a leading independent E&P company.
o In 2001, add $1.50 to $1.90 of discounted value for each dollar invested.
o Over a multi-year program, achieve 10% annual growth in production and
reserves.
o Reduce total expenses per unit of production.
(slide 11)
E&P Assets and Strategy
[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; and South Louisiana in gulf coast region of
Louisiana]
Reserves & Production @ December 31, 2000
Mid-Continent
Reserves - 34.9 Bcfe (9%)
Production - 3.5 Bcfe (10%)
Arkoma
Reserves - 200.3 Bcf (53%)
Production - 19.9 Bcf (56%)
2001 Capital - $20.5 MM (27%)
Texas/New Mexico
Reserves - 113.2 Bcfe (30%)
Production - 9.9 Bcfe (28%)
2001 Capital - $30.3 MM (41%)
South Louisiana
Reserves - 32.1 Bcfe (8%)
Production - 2.4 Bcfe (6%)
2001 Capital - $24.2 MM (32%)
o Arkoma Basin Strategy: Maintain our strong position through low-risk
development drilling.
o Mid-Continent Strategy: Harvest or trade for properties in core areas.
o Texas/New Mexico Strategy: Growth through medium-risk exploration and
exploitation.
o South Louisiana Strategy: Growth through high-potential exploration.
(slide 12)
Arkoma Basin
[map showing location of Arkoma Basin in Arkansas and Oklahoma, the Arkoma Basin
Fairway, the Ranger Anticline Prospect, the Cherokee Prospect and Pittsburg
County.]
Arkoma Basin
3-year average results
Reserve replacement: 98%
LOE Cost (incl. Taxes) ($/Mcf): $0.21
F&D Cost ($/Mcf): $0.90
Ranger Anticline
Success: 6/9 wells
Net EUR: 9.9 Bcf
F&D/Mcf: $.56
Cherokee
Success: 14/19 wells
Net EUR: 5.8 Bcf
F&D/Mcf: $1.07
o "Legacy asset" that provides SWN with a stable production/reserve base and
lower-risk drilling opportunities.
o Large acreage position of 388,000 gross
acres and 249,000 net acres.
o Competitive advantage based on 50+ years of experience in the basin.
o 2001 capital program includes drilling 53 wells with an average WI of 50%.
(slide 13)
Permian Basin
[map showing Permian Basin in west Texas and southeast New Mexico, Lea County,
Eddy County, Chavez County; acreage blocks under joint exploration agreements
with Phillips Petroleum and Energen Resources; discovery fields of Gaucho, Logan
Draw, Thistle, Pappy and Cowden Ranch; and prospect locations for Buffalo
Valley, Lonesome Dove, No Bluff, Big Bluff, Birds of Prey, Stone Mason, Alfalfa,
Butkus, B-3 and West Pappy.]
Permian Basin
3-year average results
Reserve Replacement: 290%
LOE Cost (incl. Taxes) ($/Mcfe): $0.73
F&D Cost ($/Mcfe): $1.11
Delaware Basin Acreage
Gross Acres
SWN 42,200
Phillips JV-1 24,000
Phillips JV-2 47,200
Energen JV 27,500
-------
140,900
o Growing portfolio of medium-risk exploration and exploitation opportunities.
o Reserves of less than 2.0 Bcfe in 1995 have grown to 66.2 Bcfe in 2000.
o 2001 capital program includes drilling 19 exploration wells and 6 development
wells.
(slide 14)
Overton Field, East Texas
[map showing Overton Field area by units indicating locations of active wells
and planned wells]
Overton Acquisition
East Texas - 10,000 Acres
16 Active Wells in 13 Units
(Developed at 640-Acre Spacing)
8-14 Wells Planned for 2001
Overton Field Drilling Potential
EUR (Bcfe)
--------------
# Wells Gross Net
--------- ------- -----
320 Acre Spacing 10 16 13
160 Acre Spacing 26 42 34
Total 36 58 47
=========================
o Purchased 7.5 Bcfe for $6.1 million in April 2000.
o One of the few fields left in east Texas that has not been downspaced from
640-acre units.
o Infill drilling has commenced and 8 to 14 wells are planned in 2001.
(slide 15)
South Louisiana Exploration
[map showing southern Louisiana indicating the location of the North Grosbec,
Malone, Havilah and Gloria discoveries, the Company's 3-D project areas and
proposed wells to be drilled in the area in 2001.]
North Grosbec Discovery
Gross EUR: 94.9 Bcfe
Curr. Prod.: 16.2 MMcfd & 587 Bopd
Gloria Discovery
Gross EUR: 16.1 Bcfe
Curr. Prod.: 9.4 MMcfd & 308 Bopd
Malone Discovery
Completing two wells
Havilah Discovery
Gross EUR: 16.2 Bcfe
6.2 MMcfd & 348 Bopd
o Recent Gulf Coast success:
>> Gloria discovery (50% WI) currently producing 9.4 MMcfd and 308 Bopd.
>> North Grosbec discovery (25% WI) currently producing 16.2 MMcfd and 587
Bopd. Drilling first developmental well.
>> Havilah discovery (27.5%WI) currently producing 6.2 MMcfd and 348 Bopd.
>> Malone discovery (33.3% WI) currently completing two wells.
o 2001 exploration program includes drilling 6 exploratory wells and 3
development wells.
(slide 16)
2001 Exploration Potential - 224 Net Bcfe
Gross Res. Net Res.
Spud Working Potential Potential
Prospect Name Operator Date Interest Depth Objective (Bcfe) (Bcfe)
Permian Basin
Roepke SWN Producing 92.0% 7,600 Fusselman 3.0 2.3
Alfalfa SWN Producing 92.0% 7,800 Devonian 5.7 4.0
Butkus SWN Completing 55.0% 13,400 Morrow 5.0 2.4
West Pappy SWN Completing 55.0% 8,900 Blinebry/Abo 6.0 1.6
Big D SWN Dry 85.0% 8,000 Wolfcamp 2.4 1.6
Big Bluff SWN May-01 85.0% 10,200 Morrow 10.0 7.0
Buffalo Valley SWN May-01 55.0% 9,000 Morrow 9.0 4.4
B-3 SWN Jul-01 55.0% 7,500 Blinebry 3.0 1.7
Birds of Prey SWN Jul-01 100.0% 5,000 Cherry Canyon 3.0 2.5
Stone Mason SWN Oct-01 50.0% 16,000 Devonian 50.0 18.8
Gulf Coast
Malone SWN Completing 33.3% 15,000 Miocene 50.0 12.0
Mahone SWN Drilling 50.0% 16,100 Discorbis 101.2 38.0
Whitehorse SWN May-01 50.0% 14,000 Planulina 25.0 9.4
Horeb SWN Jun-01 21.0% 14,300 Frio 252.0 39.7
Tigris SWN Aug-01 50.0% 13,600 Frio 74.0 27.8
Handel SWN Sep-01 33.0% 11,200 Frio 30.0 7.7
Crowne SWN Nov-01 40.0% 13,500 Planulina 90.0 25.9
Tulleymore SWN Mar-02 40.0% 13,500 Planulina 60.0 17.3
Total Reserve Potential 765.6 224.1
Forward-Looking Statement
(slide 17)
E&P Capital Investments
[graph showing E&P capital investments from 1998 through the 2001 budgeted
program, broken out by Property Acquisitions, Capitalized Expenses, Leasehold &
Seismic, Development Drilling, and Exploration Drilling; Company's 2001 budgeted
capital investment program has 28% allocated to Arkoma & Exploitation, 32% to
the Gulf Coast and 40% to the Permian & East Texas.]
o Well-balanced capital program in 2001:
>> Low risk Arkoma and other exploitation ($21 MM, 28%),
>> Medium risk Permian Basin and East Texas ($30 MM, 40%) and
>> Higher risk, but larger potential Gulf Coast ($24 MM, 32%).
o Large percentage of capital allocated to drilling in 2001 ($56 MM, 75%).
o Identified exploration inventory has a net reserve exposure of approximately
224 Bcfe.
(slide 18)
The Right People Doing the Right Things
[graph showing the Company's results in PVI, F&D Cost and Reserve Replacement
from 1995 to 2000; graph is divided between pre- and post- 1997 when new
management, new E&P team and new strategy were put in place]
Note: All metrics calculated include revisions and exclude property
acquisitions. PVI calculated per $10 investment. 2000 PVI metric calculated at
$4.00 natural gas price at year-end 2000.
-------------------- ------- -------- ------- -------- -------- --------
1995 1996 1997 1998 1999 2000
-------------------- ------- -------- ------- -------- -------- --------
PVI $2.58 $3.19 $5.77 $11.00 $10.00 $18.00
-------------------- ------- -------- ------- -------- -------- --------
F&D Cost $7.17 $11.81 $2.48 $1.18 $1.40 $.99
-------------------- ------- -------- ------- -------- -------- --------
Reserve Replacement 30% 15% 78% 120% 108% 172%
-------------------- ------- -------- ------- -------- -------- --------
(slide 19)
Outlook for 2001
o Targets:
>> Production target of 38 Bcfe in 2001.
>> Excess cash flow goes toward long-term debt reduction.
NYMEX Commodity Price Assumptions
$3.50 Gas $4.50 Gas $5.50 Gas
$25.00 Oil $25.00 Oil $25.00 Oil
---------- ---------- ----------
>> Earnings $32 MM $37 MM $46 MM
>> EPS $1.28 $1.49 $1.84
>> Cash Flow $103 MM $112 MM $126 MM
>> CFPS $4.13 $4.48 $5.04
>> EBITDA $128 MM $136 MM $150 MM
Forward-Looking Statement
(slide 20)
The Road to V+
o Stay the Course with Our Balanced E&P Strategy.
o Build on Exploration Success.
o Reduce Debt with Excess Cash Flow.
o Deliver the Numbers.
>> Production and Reserve Growth.
>> Add Value for Every Dollar Invested.
o Increase Cash Flow Multiple to the Peer Average.
(slide 21)
Financial Summary
Year Ended
2000(1) 1999 1998(2)
-----------------------------------------
($ in million, except per share amounts)
Revenues $363.9 $280.4 $266.3
EBITDA 103.8 76.7 81.7
Net Income 20.5 9.9 9.9
Cash Flow (3) 82.4 60.8 73.7
Earnings per Share $0.82 $0.40 $0.40
Cash Flow per Share 3.29 2.44 2.96
Production Volume (Bcfe) 35.7 32.9 36.9
Avg. Gas Price per Mcf $2.88 $2.21 $2.34
Avg. Oil Price per Bbl $22.99 $17.11 $13.60
[FN]
(1) Before the effects of unusual and extraordinary items.
(2) Before the effect of a ceiling test write-down of oil and gas properties.
(3) Cash Flow is before changes in working capital.
</FN>
(slide 22)
Gas Hedges in Place Through 2002
[chart showing fixed-price and zero-cost collar gas hedges in place by quarter
for the years 2001 and 2002] New hedges since 9/30 10-Q:
Collars 17.5 Bcf
Fixed .7 Bcf
Note: Details of the Company's hedging position was previously released in an
8-K filing on December 8, 2000.
(slide 23)
[Map showing location of the Atchafalaya Mini-Basin in Assumption, St. Martin &
Iberia Parishes in the E. Atchafalaya & Boure 3-D Surveys, the Jeanerette 3-D
Survey, and the North Jeanerette prospect]
North Grosbec Discovery
Gross EUR: 94.9 Bcfe
WI: 25%
Curr. Prod.: 16.2 MMcfd & 587 Bopd
Gloria Discovery
Gross EUR: 16.1 Bcfe
WI: 50%
Curr. Prod.: 9.4 MMcfd & 308 Bopd
Malone Discovery
Completing two wells
(slide 24)
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, the
value that the Company's gas distribution segment may bring in exploring sales
opportunities for this 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 various other factors beyond the Company's control.