The left side of this slide contains a photograph of a rock climber scaling a steep cliff with a mountain range in the background. The caption above reads "High adventure." The company's formulais located in the left side of the picture. The top-right corner of this slide contains the company logo.
(Slide 1) Southwestern Energy Company
General Information
Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in natural gas and oil exploration and production and natural gas gathering and marketing.
Market Data as of December 31, 2010
NYSE: SWN
Shares of Common Stock Outstanding
346,783,295
Market Capitalization
$12,980,000,000
Institutional Ownership
84.9%
Management and Board Ownership
3.0%
52-Week Price Range
$31.44 (9/17/10) - $51.65 (1/5/10)
Investor Contacts
Greg D. Kerley Executive Vice President and Chief Financial Officer
Phone:
(281) 618-4803
Fax:
(281) 618-4820
Brad D. Sylvester, CFA Vice President, Investor Relations
Phone:
(281) 618-4897
Fax:
(281) 618-4820
(Slide 2) 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. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. 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. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company’s ability to fund the company’s planned capital investments; the company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays; the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s future property acquisition or divestiture activities; the impact of the adverse outcome of any material litigation; the costs and availability of oil field personnel, services, drilling supplies, raw materials, and equipment; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
The SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.
The contents of this presentation are current as of January 6, 2011.
(Slide 3) About Southwestern
* Focused on exploration and production of natural gas.
* 3,657 Bcfe of reserves; 12.2 R/P at year-end 2009.
* E&P strategy built on organic growth through the drillbit.
* Over 75% of planned E&P capital allocated to drilling in 2010.
* Track record of adding significant reserves at low costs.
* From 2004 to 2009, we've averaged over 40% annual production and reserve growth and annually replaced over 500% of our production at a F&D cost of $1.46 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to over $12 billion today.
* Strategy built on the Formula:
TheRight People doing theRight Things, wisely investing the cash flow from the underlyingAssetswill createValue+.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 4) Recent Developments
* First Nine Months of 2010 Highlights
* Net income of $454.6 million, up 25%(1).
* Discretionary cash flow(2) of $1.2 billion, up 15%.
* Production of 293.3 Bcfe, up 39%.
* Significant progress realized in our Fayetteville Shale play.
* Gross operated production from Fayetteville Shale was approximately 1.5 Bcf per day in October 2010, up from 1.2 Bcf per day a year ago.
* Current remaining inventory of over 9,000 wells on acreage drilled to date.
*Strong Growth and Low-Cost Operations Set the Stage for a Record 2011
* 2011 planned capital investment program of approximately $1.9 billion, down 10% from 2010 projected levels.
* 2011 gas and oil production projected to grow approximately 18% to 465 - 475 Bcfe.
* One of the lowest cost operators in the industry – cash operating costs(3) of $1.31 per Mcfe in the third quarter of 2010.
* Strong balance sheet and financial position as of September 30, 2010:
* Debt-to-book capital ratio of 31%.
* $1 billion credit facility with $617 million drawn at an average interest rate of 0.9%.
(1)
Increase in net income is from first nine months of 2009 adjusted net income of $364.8 million (a non-GAAP measure reconciled on page 33), which excludes a $558.3 million after-tax non-cash ceiling impairment.
(2)
Discretionary cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure (see explanation and reconciliation on page 32).
(3)
Cash operating costs for the quarter ended September 30, 2010, include lease operating expenses ($0.85/Mcfe), general and administrative expenses ($0.28/Mcfe), taxes other than income taxes ($0.12/Mcfe) and net interest expense ($0.06/Mcfe).
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 5) Proven Track Record
This slide contains bar charts for the periods ended December 31.
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Production (Bcfe)
36
40
40
41
54
61
72
113
195
300
393-401E
465-475E
Reserve Replacement (%)
211%
155%
215%
313%
364%
399%
386%
474%
523%
592%
EBITDA ($MM)(1)
$104
$134
$99
$151
$255
$346
$415
$675
$1,362
$1,368
F&D Cost ($/Mcfe)
$0.92
$1.59
$0.99
$1.32
$1.43
$1.70
$2.72
$2.55
$1.53
$0.86
Note: Reserve data includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 34.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 6) Areas of Operations
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and Pennsylvania with shadings to denote the Conventional Arkoma Basin, the East Texas region, the Fayetteville Shale and the Marcellus Shale.
Exploration & Production Segment
* 2009:
3,657 Bcfe of Reserves
~100% Natural Gas
Production - 300.4 Bcfe
* 2010 Est. Production: 393-401 Bcfe
* 2011 Est. Production: 465-475 Bcfe
Conventional Arkoma
* Reserves: 208 Bcf (6%)
* Production: 22.0 Bcf (7%)
* Net Acres: 338,486 (12/31/09)
Fayetteville Shale
* Reserves: 3,117 Bcf (85%)
* Production: 243.5 Bcf (81%)
* Net Acres: 888,695 (12/31/09)
East Texas
* Reserves: 330 Bcfe (9%)
* Production: 34.9 Bcfe (12%)
* Net Acres: 115,199 (12/31/09)
Marcellus Shale
* Net Acres: ~175,000 (12/31/10)
* Southwestern's E&P segment operates in Arkansas, Texas, Oklahoma and Pennsylvania.
* Midstream Services segment provides marketing and gathering services for the E&P business.
Notes:
2009 reserve data by area does not add to year-end totals for the company due to the exclusion of Marcellus Shale reserves.
Conventional Arkoma acreage excludes 125,402 net acres in the conventional Arkoma Basin operating area that are also within the company's Fayetteville Shale focus area.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 7) Capital Investments
This slide contains a bar chart of company capital investments, summarized as follows:
2011
2005
2006
2007
2008
2009
2010E
Plan
(in millions)
Corporate & Other
$ 16
$ 32
$ 16
$ 17
$ 29
$ 80
$60
Midstream Services
$ 16
$ 49
$ 107
$ 183
$ 214
$ 270
$225
Drilling Rigs
$ 35
$ 94
$ 5
$ -
$ -
$ -
$ -
Property Acquisitions
$ -
$ 18
$ 2
$ -
$ 4
$ -
$ -
Cap. Expense & Other E&P
$ 32
$ 62
$ 77
$ 153
$ 190
$ 220
$255
Leasehold & Seismic
$ 61
$ 70
$ 166
$ 149
$ 114
$ 205
$195
Development Drilling
$ 287
$ 421
$ 1,110
$ 1,255
$ 1,254
$ 1,220
$1,151
Exploration Drilling
$ 36
$ 196
$ 20
$ 39
$ 4
$ 105
$14
Total
$ 483
$ 942
$ 1,503
$ 1,796
$ 1,809
$ 2,100
$1,900
This slide also contains a pie chart of the company's planned 2011 capital investments by area of operation, summarized as follows:
% of Total
Capital Investments
Arkoma Fayetteville Shale
60%
Appalachia
14%
Midstream
12%
New Ventures
9%
Corp/Other
3%
East Texas
1%
Arkoma
1%
* E&P capital program heavily weighted to low-risk development drilling in 2011.
* Plan to invest approximately $1.4 billion in the Fayetteville Shale play in 2011.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 8) Fayetteville Shale Focus Area
This slide contains a map of the Fayetteville Shale Focus Area in Arkansas. Well locations for all wells drilled from inception of the play through Q3 2010 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, 3MMcf/d to 6MMcf/d and greater than 6MMcf/d. The Mississippi Embayment is also indicated on the map.
* At September 30, 2010, SWN held approximately 889,000 net acres in the Fayetteville Shale play area (equivalent to approximately 1,400 square miles).
* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.
* During the first nine months of 2010, SWN drilled and completed 394 operated wells, all of which were horizontal wells fracture stimulated with slickwater.
* We plan to drill approximately 440-450 operated wells in 2011.
Notes: Rates are AOGC Form 13 and Form 3 test rates.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
* Continuous improvement in our Fayetteville Shale operations.
* Current remaining inventory of over 9,000 wells on approximately 600,000 net acres drilled to date, greater than 10 years of drilling at current pace.
* Contiguous acreage position allows us economies of scale and operating flexibility.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 10) Fayetteville Shale - Horizontal Well Performance
Time Frame
Wells Placed on Production
Average IP Rate (Mcf/d)
30th-Day Avg Rate (# of wells)
60th-Day Avg Rate (# of wells)
Avg Lateral Length
1st Qtr 2007
58
1,261
1,066
(58)
958
(58)
2,104
2nd Qtr 2007
46
1,497
1,254
(46)
1,034
(46)
2,512
3rd Qtr 2007
74
1,769
1,510
(72)
1,334
(72)
2,622
4th Qtr 2007
77
2,027
1,690
(77)
1,481
(77)
3,193
1st Qtr 2008
75
2,343
2,147
(75)
1,943
(74)
3,301
2nd Qtr 2008
83
2,541
2,155
(83)
1,886
(83)
3,562
3rd Qtr 2008
97
2,882
2,560
(97)
2,349
(97)
3,736
4th Qtr 2008
(1)
74
3,350
(1)
2,722
(74)
2,386
(74)
3,850
1st Qtr 2009
(1)
120
2,992
(1)
2,537
(120)
2,293
(120)
3,874
2nd Qtr 2009
111
3,611
2,833
(111)
2,556
(111)
4,123
3rd Qtr 2009
93
3,604
2,640
(92)
2,275
(92)
4,100
4th Qtr 2009
122
3,727
2,674
(122)
2,360
(120)
4,303
1st Qtr 2010
(2)
106
3,197
(2)
2,388
(106)
2,123
(106)
4,348
2nd Qtr 2010
143
3,449
2,575
(141)
2,329
(141)
4,532
3rd Qtr 2010
145
3,281
2,439
(118)
2,309
(73)
4,503
Note: Data as of September 30, 2010.
(1) The significant increase in the average initial production rate for the fourth quarter of 2008 and the subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline.
(2) In the first quarter of 2010, the company's results were impacted by the shift of all wells to "green completions" and the mix of wells, as a large percentage of wells were placed on production in the shallower northern and far eastern borders of the company's acreage.
(Slide 11) Fayetteville Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through September 30, 2010, for the company's horizontal wells drilled in the Fayetteville Shale. This graph displays four composite curves, one composite curve showing the SW/XL normalized production from all the company's horizontal wells and three composite curves showing the results of the company's horizontal wells with laterals greater than 3,000 feet, greater than 4,000 feet, and greater than 5,000 feet. The production data is compared to 2.0 Bcf, 3.0 Bcf, and 4.0 Bcf typecurves from the company's reservoir simulation shale gas model. Well counts and respective days of production are also displayed, as follows:
Days of Production
Total Well Count
Horizontal Wells with Laterals > 3,000 Feet
Horizontal Wells with Laterals > 4,000 Feet
Horizontal Wells with Laterals > 5,000 Feet
0
1,482
1,155
554
134
100
1,347
999
452
99
200
1,189
814
321
56
300
1,078
731
267
38
400
960
617
209
25
500
845
515
156
12
600
704
394
96
6
700
593
290
54
5
800
516
227
27
3
900
416
144
7
0
1000
326
73
1
0
1100
255
26
0
0
1200
175
9
0
0
1300
129
2
0
0
1400
66
2
0
0
1500
34
1
0
0
Note: Data as of September 30, 2010. Excludes wells with mechanical problems (30).
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 12) Fayetteville Shale - Gross Production
This slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to October 23, 2010. Gross operated production of approx. 1,536 MMcf/d as of October 23, 2010. 2009 Fayetteville Shale F&D cost of $0.69/Mcf. Periods of production affected by pipeline curtailment issues are denoted.
(Slide 13) Midstream - Adding Value Beyond the Wellhead
This slide contains a map of several counties in Arkansas where the company's Fayetteville Shale Focus Area is located. These counties include Johnson, Pope, Van Buren, Cleburne, Logan, Yell, Conway, Faulkner and White. Lines trace DeSoto Gathering Lines and the Ozark, Centerpoint, Boardwalk, NGPL, MRT and TETCO transmission pipelines. Compression facilities are also indicated on the map.
*
Midstream assets provide rapidly growing revenue stream and potential future funding source.
*
At October 25, 2010, gathering approximately 1,717 MMcf per day through 1,524 miles of gathering lines, up from approximately 1,304 MMcf per day the same time a year ago.
*
Midstream EBITDA(1) of $205 - $210 million projected for 2010.
*
Phase 1 Fayetteville Lateral of Boardwalk Pipeline placed in-service December 2008. (FT volumes of 800,000 MMBtu/d on Fayetteville Lateral and 640,000 MMBtu/d on Greenville Lateral).
*
Fayetteville Express Pipeline placed in-service October 2010 (FT volumes of 1,200,000 dkth/d).
Note: Map as of September 30, 2010.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 34.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 14)
Marcellus Shale
This slide contains a map of several counties in Pennsylvania and New York and certain well production data. The company's acreage positions are highlighted. The locations of the company's test wells are shown on the map: Greenzweig, Range Trust, Price and Lycoming. Lines trace the Transco, Tennessee Gas, Millennium and Stagecoach transmission pipelines.
*
At December 31, 2010, SWN held approximately 175,000 net acres in Northeast Pennsylvania with Marcellus Shale potential.
*
In 2011, we plan to drill with 1-2 operated rigs and participate in 40-45 Marcellus wells, all of which are planned to be operated.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 15) New Ventures – New Brunswick, Canada Project
This slide contains a map of the Province of New Brunswick, Canada. The acreage on which the company has obtained licenses to explore are highlighted on the map: Marysville (2,309,247 acres) and Cocagne (209,271 acres). The McCully Field, Stoney Creek Field, M&NE Pipeline and the Green Road G-41 well are denoted on the map. The 2010 2D Seismic Test locations of Doaktown and Killams Mills are also denoted on the map.
* SWN currently holds exploration licenses to over 2.5 million acres within the Maritimes Basin
* Principal targets are the conventional and unconventional sandstone and shale reservoirs of the Horton Group (Frederick Brook Shale)
* Oil and gas production from fields along southern flank:
* McCully - reserves 190 bcfg
* Stoney Creek - cum 800,000 bo, 30 bcfg
* 3-year initial exploration license to complete work program
* $47MM total work commitment with options for multiple 5-year extension leases
* Maximum 12.5% royalty
(Slide 16) Outlook for 2011
* Production target of 465 - 475 Bcfe in 2011 (estimated growth of ~18%).
2010
2011 Guidance
Guidance(1)
NYMEX Price Assumptions
$4.00 Gas
$4.00 Gas
$4.50 Gas
$5.00 Gas
$80.00 Oil
$70.00 Oil
$70.00 Oil
$70.00 Oil
Adj. Net Income
$580-$590 MM
$460-$470 MM
$555-$565 MM
$660-$670 MM
Adj. Diluted EPS
$1.66-$1.69
$1.31-$1.34
$1.59-$1.62
$1.89-$1.92
EBITDA(2)
$1,580-$1,590 MM
$1,500-$1,510 MM
$1,660-$1,670 MM
$1,825-$1,835 MM
Net Cash Flow (2)
$1,535-$1,545 MM
$1,460-$1,470 MM
$1,615-$1,625 MM
$1,770-$1,780 MM
CapEx
$2,100 MM
$1,900 MM
$1,900 MM
$1,900 MM
Debt %
28%-30%
32%-34%
30%-32%
28%-30%
(1) 2010 guidance numbers include actual results through Q3 2010 and projected results based upon NYMEX price assumptions held flat for the balance of 2010.
(2) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 32 and 34.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17) The Road to V+
* Invest in the Highest PVI Projects.
* Flexibility in 2011 Capital Program.
* Maintain Strong Balance Sheet.
* Deliver the Numbers.
* Production and Reserves.
* Maximize Cash Flow.
* Continue to Tell Our Story.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 18) Appendix
(Slide 19) Financial & Operational Summary
Nine Months Ended Sept. 30,
Year Ended December 31,
2010
2009
2009
2008
2007
($ in millions, except per share amounts)
Revenues
$1,940.2
$1,521.3
$2,145.8
$2,311.6
$1,255.1
EBITDA(1)
1,199.3
963.8
(3)
1,368.1
(3)
1,362.3
(2)
675.4
Adjusted Net Income
454.6
364.8
(3)
522.7
(3)
567.9
(2)
221.2
Net Cash Flow(1)
1,184.6
1,029.6
1,441.0
1,167.5
651.2
Adjusted Diluted EPS
$1.30
$1.06
(3)
$1.52
(3)
$1.64
(2)
$0.64
(4)
Diluted CFPS(1)
$3.39
$3.00
$4.13
$3.37
$1.87
(4)
Production (Bcfe)
293.3
211.4
300.4
194.6
113.6
Avg. Gas Price ($/Mcf)
$4.76
$5.31
$5.30
$7.52
$6.80
Avg. Oil Price ($/Bbl)
$75.39
$49.47
$54.99
$107.18
$69.12
Finding Cost ($/Mcfe)(5)
$0.86
$1.53
$2.55
Reserve Replacement (%)(5)
592%
523%
474%
(1) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow, EBITDA and diluted CFPS are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 32 and 34.
(2) Adjusted net income and adjusted diluted EPS for 2008 includes after-tax gain on sale of utility assets of $35.4 million ($0.10 per diluted share) during the third quarter of 2008 (while EBITDA includes the pre-tax gain on sale of $57.3 million).
(3) Adjusted net income and adjusted diluted EPS for 2009 exclude a $558.3 million after-tax non-cash ceiling test impairment and both are non-GAAP financial measures (while EBITDA excludes the pre-tax non-cash ceiling test impairment of $907.8 million). See explanation and reconciliation of adjusted net income and adjusted diluted EPS on page 33.
(4) Diluted EPS and diluted CFPS have been adjusted to reflect the two-for-one stock split effected on March 25, 2008.
(5) Includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(Slide 20) Gas Hedges in Place Through 2012
This slide contains a bar chart detailing gas hedges in place by quarter for year 2010, year 2011 and year 2012. A summary of these gas hedges is as follows:
Average Price per Mcf
Percent
Type
Hedged Volumes
(or Floor/Ceiling)
Hedged
2010
Swaps
91.2 Bcf
$6.75
23%
Collars
30.0 Bcf
$6.80 / $8.43
8%
2011
Swaps
109.9 Bcf
$5.46
23%
Collars
62.1 Bcf
$5.09 / $6.50
13%
2012
Swaps
90.0 Bcf
$5.00
-
Collars
80.5 Bcf
$5.50 / $6.67
-
Note: SWN has hedged an additional 84 Bcf of natural gas in 2013 at $5.00 per Mcf.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 21)
SWN is One of the Lowest Cost Operators
This slide contains a bar graph that compares SWN to its competitors in terms of Lifting Cost per Mcfe of production (3 year average).
Lifting Cost per Mcfe
Of Production
(3 year average)
Southwestern Energy Company
$0.93
EOG Resources
$1.04
Noble Energy
$1.05
Ultra Petroleum
$1.08
Chesapeake Energy
$1.22
Range Resources
$1.23
Forest Oil
$1.25
Cabot Oil & Gas
$1.51
Devon Energy
$1.55
Quicksilver Resources
$1.56
Newfield Exploration
$1.57
Anadarko Petroleum
$1.68
Cimarex Energy
$1.73
Sandridge Energy
$1.80
Pioneer Natural Resources
$1.89
St. Mary Land & Exploration
$1.92
Apache
$1.97
Denbury Resources
$3.35
This slide also contains a bar graph comparing SWN to its competitors in terms of Finding & Development Cost per Mcfe (3 year average).
Finding & Development Cost
per Mcfe
(3 year average)
Ultra Petroleum
$1.21
Southwestern Energy Company
$1.34
Range Resources
$1.93
EOG Resources
$1.93
Quicksilver Resources
$1.99
Denbury Resources
$2.30
Newfield Exploration
$2.52
Devon Energy
$2.54
Cabot Oil & Gas
$2.71
Anadarko Petroleum
$2.90
Forest Oil
$3.02
Chesapeake Energy
$3.36
Apache
$3.76
Pioneer Natural Resources
$3.99
Noble Energy
$4.10
Cimarex Energy
$4.19
Sandridge Energy
$7.56
St. Mary Land & Exploration
$7.79
Source: John S. Herold Database and public filings.
Note:
All data as of December 31, 2007, 2008 and 2009.
Lifting Cost per Mcfe defined as lease operating expenses plus production taxes divided by production.
F&D Cost per Mcfe defined as the three-year sum of costs incurred in natural gas and oil exploration and development divided by the three-year sum of reserve additions from extensions and discoveries, revisions and purchases.
(Slide 22)
East Texas
This slide contains a map of several counties in East Texas and Louisiana and certain well production data. The company's Overton and Angelina River Trend acreage positions are highlighted. The James Lime Horizontals, the Haynesville/Middle Bossier Horizontals, the Haynesville Shale Prospective Area and the East Texas Salt Basin are also denoted on the map. The city of Tyler, Texas is displayed as a reference point.
James Lime Horizontals
52 Operated Wells
Avg IP Rate - - 9.0 MMcf/d
Haynesville/Middle Bossier Horizontal Well IPs
First Well:
13.2 MMcf/d
Second Well:
WOC
Third Well:
WOC
CHK
HK
Other Wells
253 Wells
123 Wells
192 Wells
Avg IP: 12.4 MMcf/d
Avg IP: 13.5 MMcf/d
Avg IP: 8.7 MMcf/d
* Entered area in 2000 with purchase of 10,800 acres at Overton for $6.1 million.
* Current acreage position of 24,400 gross acres at Overton and 135,400 gross acres at Angelina.
* In June 2010, we sold the Haynesville/Middle Bossier producing rights on approximately 20,000 net acres for $355 million. We currently hold approximately 10,500 net acres that are prospective for the Haynesville/Middle Bossier.
* Current 2011 capital program of $20 million, which includes participating in approximately 8-10 gross wells.
Sources: Southwestern Energy Company, RBC Capital Markets
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 23)
Fayetteville Shale Activity Compared to the Barnett
This slide contains bar charts displaying the number of wells drilled in the Barnett Shale Play and the Fayetteville Shale Play, summarized as follows:
Barnett Shale Play
*1981 – 1st Well Drilled
*1992 – 1st Horizontal Well Drilled
*1997 – 1st Slickwater Frac
1981-1989
Avg. 7 Vertical Wells/Year
1990-1994
Avg. 28 Vertical Wells/Year
1995-1999
Avg. 75 Vertical Wells/Year
2000
Vertical Wells Drilled
Horizontal Wells Drilled
165
0
2001
Vertical Wells Drilled
Horizontal Wells Drilled
408
1
2002
Vertical Wells Drilled
Horizontal Wells Drilled
669
2
2003
Vertical Wells Drilled
Horizontal Wells Drilled
663
70
2004
Vertical Wells Drilled
Horizontal Wells Drilled
524
260
2005
Vertical Wells Drilled
Horizontal Wells Drilled
351
701
2006
Vertical Wells Drilled
Horizontal Wells Drilled
276
1,214
2007
Vertical Wells Drilled
Horizontal Wells Drilled
178
2,117
2008
Vertical Wells Drilled
Horizontal Wells Drilled
145
2,508
2009
Vertical Wells Drilled
Horizontal Wells Drilled
54
1,586
Fayetteville Shale Play
*Q2 2004 – 1st Well Drilled
*Q1 2005 – 1st Horizontal Well Drilled
*Q3 2005 – 1st Slickwater Frac
2004
Vertical Wells Drilled
Horizontal Wells Drilled
14
0
2005
Vertical Wells Drilled
Horizontal Wells Drilled
37
13
2006
Vertical Wells Drilled
Horizontal Wells Drilled
12
103
2007
Vertical Wells Drilled
Horizontal Wells Drilled
13
419
2008
Vertical Wells Drilled
Horizontal Wells Drilled
14
690
2009
Vertical Wells Drilled
Horizontal Wells Drilled
2
858
Source: Republic Energy Co., PI-Dwights (IHS Energy), Southwestern Energy
(Slide 24)
Fayetteville Shale Production Compared to the Barnett
The graph contained in this slide displays production volumes in MMcf/d for the Fayetteville Shale over a more than 5-year period and the Barnett Shale over a more than 26-year period. Total Fayetteville Shale Field average daily production for July 2010 was 2,166 MMcf/d.
A box accompanying the graph states:
We collapsed the “learning curve” dramatically; Paradigm shift in gas prices
The graphs contained in this slide compare the daily statewide demand for water in Arkansas by source to the average daily amount used by Southwestern Energy by source.
Statewide Demand:
11,500 million gallons/day
33% Ground Water
66% Surface Water
SWN Operations Demand:
10 million gallons/day (600 Wells/year)
20% Recycle/Reused Water SGW, FBW, & PW
80% Surface Water
A box accompanying the graphs states:
SWN Operations Less than 0.5% of State’s water demand
* In Arkansas, 43,000 million gallons/day is generated in runoff.
* Capturing more surface water by building ponds utilizes water that would otherwise be lost.
Source: U.S. Geological Survey, Central Arkansas Water, Southwestern Energy Company estimates.
Shallow Ground Water (SGW) – Ground water recovered from shallow formations during the air drilling process.
Flow Back Water (FBW) – Frac Fluid that is recovered from the well after the fracture stimulation.
Produced Water (PW) – Natural formation water that is returned to the surface throughout the producing life of the well.
(Slide 26)
Drilling & Completion Major Cost Categories
Average 2010 Fayetteville Shale Well Cost Estimate
This slide displays the estimated average 2010 major well cost categories as a proportion to the total average well costs.
Average 2010 Fayetteville Shale Well Costs
(in thousands)
Fracture Stimulation
$780
Rig
390
OCTG
300
Drilling Fluids
130
Directional Drilling
120
Other
120
Wireline
120
Location
100
Water Treatment/Disposal
100
Supervision
95
Rentals
90
Trucking & Transportation
75
Wellhead & Surface Equipment
60
Bits
55
Coil Tubing
55
Environmental & Restoration
55
Surface Rentals
55
D&C Fluids
50
Special Services
40
Cementing
30
Fuel & Water
30
Land & Damages
25
Formation Evaluation
20
Major Cost Categories
$2,895
(Slide 27)
U.S. Gas Consumption and Sources
This slide displays U.S. dry gas production versus U.S. gas consumption in Bcf from 1975 to present. Net imports for the same period are also given. U.S. gas production rising in recent years.
Source: EIA
(Slide 28) U.S. Electricity Consumption
This line graph shows U.S. electricity consumption in billion kilowatt-hours per month from 1990 to present.
Source: Edison Electric Institute
(Slide 29)
U.S. Electricity Consumption
This slide contains a chart showing Electricity Generation by Energy Source as a percentage of total.
Total 4,119 Billion kWh in 2008.
Energy Source
% of Total Electricity Generation
Coal
48.2%
Natural Gas
21.4%
Nuclear
19.6%
Hydroelectric
6.0%
Other Renewables
3.1%
Petroleum
1.1%
Other Gases
0.3%
Other
0.3%
Source: EIA
Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2008 compared to Electricity Generated in 2008.
While coal and nuclear power plants operate near their maximum capacity, natural gas power plants are only running at 23% of their capacity.
2008 Generation
2008 Capacity*
Unused Capacity
Natural Gas
100,108
430,697
77%
Coal
227,670
333,035
32%
Nuclear
92,030
105,764
13%
*Excludes standby units
Source: EIA
(Slide 30) U.S. Gas Drilling and Prices
This line graph denotes the number of rigs drilling for gas and the gas price in dollars per MMBtu through the period 2000 to present.
Source: Baker Hughes, Bloomberg
(Slide 31) Oil and Gas Price Comparison
This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1994 to present.
Source: Bloomberg
(Slide 32)
Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow
We report our financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods. One such non-GAAP financial measure is net cash flow. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred. These adjusted amounts are not a measure of financial performance under GAAP.
9 Months Ended September 30,
12 Months Ended December 31,
2010
2009
2009
2008
2007
(in thousands)
(in thousands)
Net cash provided by operating activities
$1,215,062
$989,526
$1,359,376
$1,160,809
$622,735
Add back (deduct):
Change in operating assets and liabilities
(30,507)
40,098
81,652
6,685
28,435
Net cash flow
$1,184,555
$1,029,624
$1,441,028
$1,167,494
$651,170
2010 Guidance
2011 Guidance
NYMEX Commodity Price Assumption
$4.00 Gas
$4.00 Gas
$4.50 Gas
$5.00 Gas
$80.00 Oil
$70.00 Oil
$70.00 Oil
$70.00 Oil
($ in millions)
($ in millions)
Net cash provided by operating activities
$1,535 - $1,545
$1,460 - $1,470
$1,615-$1,625
$1,770-$1,780
Add back (deduct):
Assumed change in operating assets and liabilities
--
--
--
--
Net cash flow
$1,535 - $1,545
$1,460 - $1,470
$1,615-$1,625
$1,770-$1,780
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 33) Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income
Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
9 Months Ended
12 Months Ended
September 30, 2009
December 31, 2009
($ in thousands)
(per share)
($ in thousands)
(per share)
Net loss attributable to SWN
$(193,476)
$(0.56)
$(35,650)
$(0.10)
Add back:
Impairment of natural gas & oil properties (net of taxes)
558,305
1.62
558,305
1.62
Adjusted net income
364,829
$1.06
$522,655
$1.52
(Slide 34)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.
9 Months Ended September 30,
12 Months Ended December 31,
2010
2009
2009
(1)
2008
2007
2006
2005
2004
2003
2002
2001
2000
($ in thousands)
Net income (loss)attributable to SWN
$454,607
$(193,476)
(2)
$(35,650)
(2)
$567,946
$221,174
$162,636
$147,760
$103,576
$48,897
$14,311
$35,324
$20,461
(6)
Add back:
Net interest expense
19,277
12,027
18,638
28,904
23,873
679
15,040
16,992
17,311
21,466
23,699
24,689
Provision (benefit) for income taxes
291,116
(118,582)
(3)
(16,363)
(3)
350,999
135,855
99,399
86,431
59,778
28,372
(5)
8,708
21,917
11,457
Depreciation, depletion and amortization
434,307
1,263,801
(4)
1,401,470
(4)
414,460
294,500
151,795
96,641
74,919
56,833
54,095
53,003
47,505
EBITDA
$1,199,307
$963,770
$1,368,095
$1,362,309
$675,402
$414,509
$345,872
$255,265
$151,413
$98,580
$133,943
$104,112
(6)
(1) Net income for the Midstream Services segment was $73,950, depreciation, depletion and amortization was $19,213, net interest expense was $3,401 and provision for income taxes was $45,303.
(2) Net income (loss) includes the after tax $558.3 million non-cash ceiling impairment of our natural gas and oil properties recorded in Q1 2009.
(3) Provision (benefit) for income taxes includes the ($349.5) million income tax benefit related to the non-cash ceiling impairment of our natural gas and oil properties recorded in Q1 2009.
(4) Depreciation, depletion and amortization includes the $907.8 million non-cash ceiling impairment of our natural gas and oil properties recorded in Q1 2009.
(5) Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.
(6) 2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.
The table below reconciles forecasted EBITDA with forecasted net income for 2010 and 2011, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2010 and 2011, including current hedges in place:
2010 Guidance
2011 Guidance
Overall Corporate
Overall Corporate
NYMEX Commodity Price Assumption
Midstream
NYMEX Commodity Price Assumption
$4.00 Gas
Services
$4.00 Gas
$4.50 Gas
$5.00 Gas
$80.00 Oil
Segment(1)
$70.00 Oil
$70.00 Oil
$70.00 Oil
($ in millions)
Net income attributable to SWN
$580 - $590
$93 - $96
$460-$470
$555-$565
$660-$670
Add back:
Provision for income taxes
371 - 377
59 - 61
294-300
355-361
422-428
Interest expense
27 - 28
16 - 17
38-39
37-38
35-36
Depreciation, depletion and amortization
590 - 595
29 - 30
705-710
705-710
705-710
EBITDA
$1,580-$1,590
$205-$210
$1,500-$1,510
$1,660-$1,670
$1,825-$1,835
(1)Midstream Services segment results assume NYMEX commodity prices of $4.00 per Mcf for natural gas and $80.00 per barrel for crude oil for 2010.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
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is located in the left side of the picture. The top-right corner of this slide contains the company logo.