The left side of this slide contains a photograph of a pulley system. Each new line added to a pulley reduces the force needed to successfully lift an object. The basic block and tackle is our formula.
(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 May 3, 2012
NYSE: SWN
Shares of Common Stock Outstanding
349,124,547
Market Capitalization
$10,809,000,000
Institutional Ownership
90.2%
Management and Board Ownership
2.8%
52-Week Price Range
$27.85 (4/20/12) - $49.00 (7/22/11)
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 facts and 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 government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives; the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; 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 against the company; the effects of weather; increased competition and regulation; 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 May 3, 2012.
(Slide 3) About Southwestern
* Focused on exploration and production of natural gas.
* 5.9 Tcfe of reserves; 11.8 R/P at year-end 2011.
* E&P strategy built on organic growth through the drillbit.
* Over 80% of planned E&P capital allocated to drilling in 2012.
* Track record of adding significant reserves at low costs.
* From 2006 to 2011, we’ve averaged over 40% annual production and reserve growth and annually replaced over 400% of our production at an F&D cost of $1.31 per Mcfe.
* Proven management team has increased Southwestern’s market capitalization from $187 million at year-end 1998 to approximately $11 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 Quarter 2012 Highlights
* Production of 133.4 Bcfe, up 16%, due to strong Fayetteville and Marcellus results.
* Drilling on 540,000 net acre position in a new unconventional horizontal oil play targeting the Lower Smackover Brown Dense formation in southern Arkansas and northern Louisiana.
* Drilling on 264,000 net acre position in a new unconventional oil play in Colorado.
* One of the lowest cost operators in the industry – finding and development costs(1) of $1.31 per Mcfe and cash operating costs(2) of $1.31 per Mcfe.
* Strong balance sheet and financial position as of March 31, 2012:
* Net debt-to-book capitalization ratio of 25%.
* Nothing drawn on unsecured revolving credit facility of $1.5 billion.
* Cash on hand of approximately $200 million.
*Strong Growth and Low-Cost Operations Set the Stage for a Record 2012
* 2012 projected capital investment program of $2.1 billion.
* 2012 production projected to grow 13%.
(1)
Finding and development costs for the twelve months ended December 31, 2011 includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment of approximately $21 million. Excluding revisions and capital investments in our sand facility, drilling rig related and ancillary equipment, our finding and development cost was $1.34/Mcfe.
(2)
Cash operating costs for the three months ended March 31, 2012, include lease operating expenses ($0.83/Mcfe), general and administrative expenses ($0.30/Mcfe), taxes other than income taxes ($0.13/Mcfe) and net interest expense ($0.06/Mcfe).
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 5) Proven Track Record
This slide contains bar charts for the periods ended December 31.
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Production (Bcfe)
36
40
40
41
54
61
72
113
195
300
405
500
Proved Reserves (Bcfe)
381
402
415
503
646
827
1,026
1,450
2,185
3,657
4,937
5,893
EBITDA ($MM)(1)
$ 104
$ 134
$ 99
$ 151
$ 255
$ 346
$ 415
$ 675
$ 1,362
$ 1,368
$ 1,612
$ 1,780
F&D Cost ($/Mcfe)
$ 0.92
$ 1.59
$ 0.99
$ 1.32
$ 1.43
$ 1.70
$ 2.72
$ 2.55
$ 1.53
$ 0.86
$ 1.01
$ 1.31
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 36.
(Slide 6) Areas of Operations
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and Pennsylvania with shadings to denote the Ark-La-Tex region, the Fayetteville Shale and the Marcellus Shale.
Exploration & Production Segment
* 2011:
5,893 Bcfe of Reserves
Production – 500.0 Bcfe
* 2012 Est. Production: 560-570 Bcfe
New Ventures
* Brown Dense – Approx. 540,000 net acres
* Colorado – Approx. 264,000 net acres
* New Brunswick – Approx. 2.5 million acres
* Undisclosed Ventures – Approx. 323,000 net acres
Fayetteville Shale
* Reserves: 5,104 Bcf (87%)
* Production: 436.8 Bcf (87%)
* Net Acres: 925,842 (12/31/11)
Ark-La-Tex
* Reserves: 447 Bcfe (7%)
* Production: 39.8 Bcfe (8%)
* Net Acres: 285,576 (12/31/11)
Marcellus Shale
* Reserves: 342 Bcf (6%)
* Production: 23.4 Bcf (5%)
* Net Acres: 186,893 (12/31/11)
* Southwestern's E&P segment operates in Arkansas, Texas, Pennsylvania, Louisiana, Oklahoma and New Brunswick.
* Midstream Services segment provides marketing and gathering services for the E&P business.
Notes:
ArkLaTex acreage excludes 125,056 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area. Reserves and acreage as of December 31, 2011. Production is a total annual amount for 2011.
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:
2012
2005
2006
2007
2008
2009
2010
2011
Plan
Corporate & Other
$ 16
$ 32
$ 16
$ 17
$ 30
$ 73
$ 69
$ 74
Midstream Services
16
49
107
183
214
271
161
183
Drilling Rigs
35
94
5
-
-
-
-
-
Property Acquisitions
-
18
2
-
-
1
-
-
Cap. Expense & Other E&P
34
62
77
153
190
185
220
254
Leasehold & Seismic
55
70
166
149
114
215
257
107
Development Drilling
293
421
1,110
1,255
1,257
1,370
1,486
1,371
Exploration Drilling
34
196
20
39
4
5
14
116
Total
$ 483
$ 942
$ 1,503
$ 1,796
$ 1,809
$ 2,120
$ 2,207
$ 2,105
Additionally, this slide contains a pie chart of the company's planned 2012 capital investments by area of operation, summarized as follows:
% of Total
Capital Investments
Fayetteville Shale
51%
Appalachia
24%
Midstream
9%
New Ventures
11%
Corp/Other
4%
Other Areas
1%
* E&P capital program heavily weighted to low-risk development drilling in 2012.
* Plan to invest over $1.2 billion in the Fayetteville Shale and over $600 million in the Marcellus Shale (including Midstream) in 2012.
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 March 30, 2012 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, greater than 3MMcf/d and greater than 6MMcf/d.
* SWN holds approx. 925,000 net acres in the Fayetteville Shale play (approx 1,400 sq. miles).
* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.
* SWN discovered the Fayetteville Shale and has first mover advantage – average acreage cost of $253 per acre with a 15% royalty and average working interest of 74%.
* We plan to drill approximately 425-435 operated wells in 2012.
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 – completed lateral length has increased 82% over the last four years while holding total well costs flat.
* Vertical integration and contiguous acreage position allow us significant economies of scale and operating flexibility.
(Slide 10) 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.
*
SWN’s Fayetteville Shale gathering system is one of the largest in the U.S.
*
At March 31, 2012, gathering approximately 2.2 Bcf per day through 1,801 miles of gathering lines, up from approximately 1.9 Bcf per day the same time a year ago.
*
SWN has total firm transportation for the Fayetteville Shale of 2.0 Bcf per day.
*
Midstream total EBITDA(1) in 2011 was $285 million. Projected EBITDA of $300-$305 million in 2012.
Note: Map as of March 31, 2012.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 36.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 11)
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, 2011, SWN held approximately 186,893 net acres in Northeast Pennsylvania.
*
At March 31, 2012, we had 24 operated Marcellus Shale horizontal wells on production in Bradford County. Daily gross operated production was approximately 122 MMcf per day.
*
Currently running 2 operated rigs with plans to drill 70 to 80 wells in 2012.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 12)
Marcellus Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through March 31, 2012, for the company's horizontal wells drilled in the Marcellus Shale. This graph displays a composite curve showing the results of the company's horizontal wells with less than 9 stages (1 well), 9-12 stages (13 wells), and greater than 12 stages (8 wells).The production data is compared to 10 Bcf, 8 Bcf, 6 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model.
Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Marcellus Shale from September 1, 2010 to March 31, 2012. Gross operated production of approx. 122 MMcf/d as of March 31, 2012. Periods of production affected by pipeline maintenance issues are denoted.
Notes:
Data as of March 31, 2012.
(Slide 13) Brown Dense Exploration Project
This slide displays the location of the Lower Smackover Brown Dense play, located on the border of Arkansas and Louisiana, in comparison to East Texas, Arkoma Basin, and Fayetteville Shale plays. The Lower Smackover Brown Dense map highlights oil fields within the following municipalities: Wesson, McKamie-Patton, Walker Creek, Dorcheat-Macedonia, Atlanta, Magnolia, Shuler, Lisbon, El Dorado, Shadow Bend, Champagnolle, and Ora. The map also highlights gas fields within the following municipalities: Rodessa, Red Rock, Shangaloo, and Monroe. Included in the Lower Smackover Brown Dense map is the location of SWN’s first well testing, second well producing, and third well completion.
* SWN currently holds 540,000 net acres in Lower Smackover Brown Dense play. Total land cost of approx. $354 per acre; 82% NRI; leases have 4-year terms and 4-year extensions.
* Targeting oil window in Upper Jurassic age, kerogen-rich carbonate in Southern Arkansas and Northern Louisiana with horizontal drilling.
* Targeting 300 to 550 feet thick section at depths of 8,000 - 11,000 feet.
* Currently testing our first well, producing our second well and completing our third well.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
This slide displays the location of the Denver Julesburg Basin Exploration Project, located on the border of Colorado, Wyoming, Nebraska, and Kansas. The location of the Las Animas Arch, Ewertz Farm 1-58 #1-26 well, and Staner 5-58 #1-8 well is denoted.
* SWN held 264,000 net acres at 3/31/12 with a total land cost of approx. $180 per acre; 85% NRI; leases with 5-year terms and 3-year extensions.
* Targeting unconventional oil in late Pennsylvanian-age carbonates and shales with thickness of 300 – 750 feet at depths of 8,000 – 10,500 feet.
* Ewertz Farms 1-58 #1-26 is currently drilling as a 9,500’ vertical well with a 2,000’ lateral. A core will be obtained in the vertical pilot across the Marmaton.
* Staner 5-58 #1-8 will be drilled and cored as a 9,000’ vertical well.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 15) New Brunswick, Canada Exploration Project
This slide contains a map of the Province of New Brunswick, Canada. The acreage on which the company has obtained licenses to explore is 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.
* 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
(Slide 16) Outlook for 2012
* Production target of 560-570 Bcfe in 2012 (estimated growth of ~13%).
2011
2012 Guidance
Actual
NYMEX Price Assumption
$4.04 Gas
$2.50 Gas
$2.75 Gas
$3.00 Gas
$94.01 Oil
$105.00 Oil
$105.00 Oil
$105.00 Oil
Net Income
$637.8 MM
$380-$390 MM
$420-$430 MM
$460-$470 MM
Diluted EPS
$1.82
$1.09-$1.11
$1.20-$1.23
$1.31-$1.34
EBITDA(1)
$1,779.6 MM
$1,490-$1,500 MM
$1,560-$1,570 MM
$1,630-$1,640 MM
Net Cash Flow (1)
$1,766.0 MM
$1,460-$1,470 MM
$1,530-$1,540 MM
$1,600-$1,610 MM
CapEx
$2,207.2 MM
$2,105 MM
$2,105 MM
$2,105 MM
Debt %
25%
29%-31%
29%-31%
28%-30%
(1) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 34 and 36.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17) The Road to V+
* Invest in the Highest PVI Projects.
* Flexibility in 2012 Capital Program.
* Maintain Strong Balance Sheet.
* Deliver the Numbers.
* Production and Reserves.
* Maximize Cash Flow.
* Continue to Tell Our Story.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 18) Appendix
(Slide 19) Financial & Operational Summary
Quarter Ended March 31,
Year Ended December 31,
2012
2011
2011
2010
2009
($ in millions, except per share amounts)
Revenues
$656.5
$676.3
$2,952.9
$2,610.7
$2,145.8
EBITDA(1)
379.4
396.5
1,779.6
1,612.3
1,368.1
(2)
Adjusted Net Income
107.7
136.6
637.8
604.1
522.7
(2)
Net Cash Flow(1)
370.8
391.5
1,766.0
1,579.7
1,441.0
Adjusted Diluted EPS
$0.31
$0.39
$1.82
$1.73
$1.52
(2)
Diluted CFPS(1)
$1.06
$1.12
$5.05
$4.52
$4.13
Production (Bcfe)
133.4
115.0
500.0
404.7
300.4
Avg. Gas Price ($/Mcf)
$3.49
$4.12
$4.19
$4.64
$5.30
Avg. Oil Price ($/Bbl)
$104.39
$92.11
$94.08
$76.84
$54.99
Finding Cost ($/Mcfe)(3)
$1.31
$1.02
$0.86
Reserve Replacement (%)(3)
299%
430%
592%
Net Debt/Proved Reserves ($/Mcfe)
$0.23
$0.22
$0.27
Net Debt/Avg. Daily Production ($/Mcfe)
$999
$928
$969
$972
$1,197
Net Debt/Total Capitalization
25%
28%
25%
27%
30%
(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 34 and 36.
(2) Adjusted net income and adjusted diluted EPS in 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 35.
(3) Includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(Slide 20) Gas Hedges in Place Through 2013
This slide contains a bar chart detailing gas hedges in place by quarter for year 2011, year 2012 and year 2013. A summary of these gas hedges is as follows:
Average Price per Mcf
Percent
Type
Hedged Volumes
(or Floor/Ceiling)
Hedged
2012
Swaps
185.2 Bcf
$5.02
33%
47%
Collars
80.5 Bcf
$5.50 / $6.67
14%
2013
Swaps
185.2 Bcf
$5.06
-
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)
Ultra Petroleum
$0.86
Range Resources
$0.89
Southwestern Energy Company
$0.93
Cabot Oil & Gas
$0.98
Chesapeake Energy
$1.05
Forest Oil
$1.05
Noble Energy
$1.06
EOG Resources
$1.19
Anadarko Petroleum
$1.39
SM Energy
$1.45
Devon Energy
$1.49
Cimarex Energy
$1.67
Pioneer Natural Resources
$1.81
Newfield Exploration
$1.84
Apache
$1.92
Sandridge Energy
$2.10
Marathon
$2.16
Occidental Petroleum
$2.18
Murphy
$2.22
Denbury Resources
$3.87
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)
Range Resources
$0.87
Southwestern Energy Company
$1.05
Cabot Oil & Gas
$1.30
Ultra Petroleum
$1.83
Devon Energy
$1.94
Cimarex Energy
$2.09
Chesapeake Energy
$2.21
EOG Resources
$2.23
Noble Energy
$2.29
Pioneer Natural Resources
$2.34
Marathon
$2.36
Anadarko Petroleum
$2.50
Denbury Resources
$2.62
SM Energy
$2.83
Chesapeake Energy
$3.05
Sandridge Energy
$3.32
Occidental Petroleum
$3.35
Murphy
$3.44
Forest Oil
$3.56
Apache
$3.87
Source: Public filings
Note:
All data as of December 31, 2009, 2010 and 2011. APC - Anadarko Petroleum, APA - Apache, COG - Cabot Oil & Gas, CHK - Chesapeake Energy, XEC - Cimarex Energy, DNR - Denbury Resources, DVN - Devon Energy, EOG - EOG Resources, FST - Forest Oil, MRO - Marathon Oil, MUR - Murphy Oil, NFX - Newfield Exploration, NBL - Noble Energy, OXY - Occidental Petroleum, PXD - Pioneer Natural Resources, RRC - Range Resources, SD - Sandridge Energy, SM - SM Energy, SWN - Southwestern Energy, UPL - Ultra Petroleum.
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, improved recovery, revisions and purchases.
(Slide 22)
Ark-La-Tex Division
This slide contains a map of the ArkLaTex Division, which is composed of East Texas and Arkoma Basin, in relation to Texas, Oklahoma, Arkansas, and Louisiana. The slide also contains two graphs outlining the production, capital expenditures, and reserves for East Texas and Arkoma Basin for the period extending from 2000 to 2011, summarized as follows:
Arkoma Basin
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Production (Bcfe)
19.9
22.3
19.8
18.9
20.1
20.2
20.1
23.8
24.4
22
19.2
16.3
Reserve (Bcfe)
200.3
186
188.7
211.7
239.5
271
277
304
281
208
226
194
Capex (in millions)
$ 17.6
$ 28.6
$ 18.2
$ 32.9
$ 53.2
$ 64.5
$ 97.0
$ 148.0
$ 133.0
$ 40.0
$ 13.0
$ 7.7
East Texas
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Production (Bcfe)
0.3
2.3
5.9
13.6
22.2
28.2
32
29.9
31.6
34.9
34.3
23.5
Reserve (Bcfe)
22
57.6
111
196.3
299.1
368.7
383
353
351
330
321
253
Capex (in millions)
$ 6.1
$ 30.9
$ 33.6
$ 97.3
$ 156.7
$ 183.6
$ 204.0
$ 201.0
$ 160.0
$ 167.0
$ 150.0
$ 68.0
Arkoma Basin
Acreage: 194,494 net acres (at 12/31/11)
2011 Reserves: 194 Bcf (3% of total)
2011 Production: 16.3 Bcf (3% of total)
East Texas
Acreage: 91,082 net acres (at 12/31/11)
2011 Reserves: 253 Bcfe (4% of total)
2011 Production: 23.5 Bcfe (5% of total)
* Sold Overton Field in May 2012 (23 MMcfe/d and 138 Bcfe).
Notes: Conventional Arkoma acreage excludes 125,056 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area.
Overton Field production as of May 2012; total reserves as of December 2011.
(Slide 23)
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
2,624
(93)
2,255
(93)
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
2,554
(143)
2,321
(142)
4,532
3rd Qtr 2010
145
3,281
2,448
(145)
2,202
(144)
4,503
4th Qtr 2010
159
3,472
2,678
(159)
2,294
(159)
4,667
1st Qtr 2011
137
3,231
2,604
(137)
2,238
(137)
4,985
2nd Qtr 2011
149
3,014
2,328
(149)
1,991
(149)
4,839
3rd Qtr 2011
132
3,441
2,666
(132)
2,372
(132)
4,847
4thQtr 2011
142
3,646
2,606
(142)
2,243
(142)
4,703
1st Qtr 2012
146
3,319
2,459
(120)
2,058
(58)
4,743
Note: Data as of March 31, 2012.
(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.
Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to March 2012. Gross operated production of approx. 1,988 MMcf/d as of March 31, 2012. 2011 Fayetteville Shale F&D cost of $1.13/Mcf. Periods of production affected by pipeline curtailment issues are denoted.
(Slide 24)
Fayetteville Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through December 31, 2011, 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 Bcf, 3 Bcf, and 4 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
2,347
1,909
1,159
399
100
2,202
1,811
1,101
379
200
2,046
1,633
964
321
300
1,916
1,526
866
272
400
1,738
1,337
737
202
500
1,585
1,183
604
157
600
1,436
1,073
513
120
700
1,259
898
378
70
800
1,123
767
299
45
900
1,013
678
233
30
1,000
888
564
177
18
1,100
783
448
115
8
1,200
642
330
66
4
1,300
566
264
42
5
1,400
459
181
17
1
1,500
370
104
1
0
Note: Data as of March 31, 2012. Excludes wells with mechanical problems (31).
(Slide 25)
Drilling & Completion Major Cost Categories
Average 2012 Fayetteville Shale Well Cost Estimate
This slide displays the estimated average 2012 major well cost categories as a proportion to the total average well costs.
Average 2012 Fayetteville Shale Well Cost Estimate
(in thousands)
Fracture Stimulation
$726
Rig
273
OCTG
239
Environmental & Restoration
137
Drilling Fluids
131
Directional Drilling
128
Wellhead & Surface Equipment
125
Other
119
Water Treatment/Disposal
107
Supervision
104
Surface Rentals
99
Location
95
Wireline
83
Rentals
79
Coil Tubing
75
D&C Fluids
64
Bits
52
Cementing
49
Fuel & Water
47
Trucking & Transportation
45
Formation Evaluation
43
Special Services
38
Land & Damages
8
Major Cost Categories
$2,866
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 26)
Water Demand: Perspective
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 0.09% of State’s water demand
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 27)
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 7-year period and the Barnett Shale over a more than 28-year period. Total Fayetteville Shale Field average daily production for January 2012 was 2,746 MMcf/d.
A box accompanying the graph states:
We collapsed the “learning curve” dramatically; Paradigm shift in gas prices
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 Wells/Year
1990-1994
Avg. 28 Wells/Year
1995-1999
Avg. 75 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
2010
Vertical Wells Drilled
Horizontal Wells Drilled
65
1,643
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
2010
Vertical Wells Drilled
Horizontal Wells Drilled
0
653
Source: Republic Energy Co., PI-Dwights (IHS Energy), Southwestern Energy
(Slide 29)
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 30) 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 31)
U.S. Electricity Generation
This slide contains a chart showing Electricity Generation by Energy Source as a percentage of total.
Total 4,120 Billion kWh in 2010.
Energy Source
% of Total Electricity Generation
Coal
44.9%
Natural Gas
23.8%
Nuclear
19.6%
Hydroelectric
6.1%
Other Renewables
4.1%
Petroleum
0.9%
Other Gases
0.3%
Other
0.3%
Source: EIA
Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2009 compared to Electricity Generated in 2010.
While coal and nuclear power plants operate at very high capacity, natural gas power plants are only running at 24% of their capacity.
2010 Generation
2009 Capacity*
Unused Capacity
Natural Gas
112,079
430,697
76%
Coal
211,273
333,035
38%
Nuclear
92,120
105,764
14%
*Excludes standby units
Source: EIA
(Slide 32) 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 33) 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 1997 to present.
Source: Bloomberg
(Slide 34)
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.
3 Months Ended March 31,
12 Months Ended December 31,
2012
2011
2011
2010
2009
(in thousands)
(in thousands)
Net cash provided by operating activities
$444,663
$396,479
$1,739,817
$1,642,585
$1,359,376
Add back (deduct):
Change in operating assets and liabilities
(73,843)
(4,947)
26,201
(62,906)
81,652
Net cash flow
$370,820
$391,532
$1,766,018
$1,579,679
$1,441,028
2012 Guidance
NYMEX Commodity Price Assumption
$2.50 Gas
$2.75 Gas
$3.00 Gas
$105.00 Oil
$105.00 Oil
$105.00 Oil
($ in millions)
Net cash provided by operating activities
$1,460 - $1,470
$1,530-$1,540
$1,600-$1,610
Add back (deduct):
Assumed change in operating assets and liabilities
--
--
--
Net cash flow
$1,460 - $1,470
$1,530-$1,540
$1,600-$1,610
(Slide 35)
Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income
Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
12 Months Ended
December 31, 2009
($ in thousands)
(per share)
Net loss attributable to SWN
$(35,650)
$(0.10)
Add back:
Impairment of natural gas & oil properties (net of taxes)
558,305
1.62
Adjusted net income
$522,655
$1.52
(Slide 36)
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.
3 Months ended March 31,
12 Months ended December 31,
2012
2011
2011(1)
2010
2009
2008
2007
Net income (loss) attributable to SWN
$ 107,704
$ 136,609
$ 637,769
$ 604,118
$ (35,650)
(2)
$ 567,946
$ 221,174
Add back:
Net interest expense
7,338
7,436
24,075
26,163
18,638
28,904
23,873
Provision (benefit) for income taxes
70,718
88,980
413,221
391,659
(16,363)
(3)
350,999
135,855
Depreciation, depletion and amortization
193,627
163,447
704,511
590,332
1,401,470
(4)
414,460
294,500
EBITDA
$ 379,387
$ 396,472
$ 1,779,576
$ 1,612,272
$ 1,368,095
$ 1,362,309
$ 675,402
12 Months ended December 31,
2006
2005
2004
2003
2002
2001
2000
Net income (loss) attributable to SWN
$ 162,636
$ 147,760
$ 103,576
$ 48,897
$ 14,311
$ 35,324
$ 20,461
(6)
Add back:
Net interest expense
679
15,040
16,992
17,311
21,466
23,699
24,689
Provision (benefit) for income taxes
99,399
86,431
59,778
28,372
(5)
8,708
21,917
11,457
Depreciation, depletion and amortization
151,795
96,641
74,919
56,833
54,095
53,003
47,505
EBITDA
$ 414,509
$ 345,872
$ 255,265
$ 151,413
$ 98,580
$ 133,943
$ 104,112
(6)
(1) Net income for the Midstream Services segment was $142,591 depreciation, depletion and amortization was $37,261, net interest expense was $15,049 and provision for income taxes was $90,221.
(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 2012, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2012, including current hedges in place:
2012 Guidance
Overall Corporate
NYMEX Commodity Price Assumption
Midstream Services Segment(1)
$2.50 Gas
$2.75 Gas
$3.00 Gas
$105.00 Oil
$105.00 Oil
$105.00 Oil
($ in millions)
Net income attributable to SWN
$380-$390
$420-$430
$460-$470
$135-$140
Add back:
Provision for income taxes
249-256
275-282
302-308
89-92
Interest expense
54-56
54-56
54-56
26-28
Depreciation, depletion and amortization
800-810
800-810
800-810
46-48
EBITDA
$1,490-$1,500
$1,560-$1,570
$1,630-$1,640
$300-$305
(1)
Midstream Services segment results assume NYMEX commodity prices of $2.50 per Mcf for natural gas and $105.00 per barrel for crude oil for 2012.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
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