Attached files
| file | filename |
|---|---|
| 8-K - SWN FORM 8-K INVESTOR PRESENTATION - SOUTHWESTERN ENERGY CO | swn081210form8k.htm |
EXHIBIT 99.1
Slide Presentation dated August 2010
(Cover)
Southwestern
Energy
August 2010 Update
NYSE: SWN
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 formula 
is 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 August 11, 2010
|
NYSE: SWN |
|
|
Shares of Common Stock Outstanding |
346,086,989 |
|
Market Capitalization |
$12,089,000,000 |
|
Institutional Ownership |
86.6% |
|
Management and Board Ownership |
3.0% |
|
52-Week Price Range |
$34.93 (8/11/10) - $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 Southwestern Energy Company’s (the company) 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 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 company’s ability to fund the company’s planned capital investments; 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 costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company’s future property acquisition or divestiture activities; 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 August 5, 2010.
(Slide 3)
About
Southwestern
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* Focused on exploration and production of natural gas. | |
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* 3,657 Bcfe of reserves; ~100% natural gas; 12.2 R/P at year-end 2009. |
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* E&P strategy built on organic growth through the drillbit. | |
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* Over 75% of planned E&P capital allocated to drilling in 2010. |
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* Track record of adding significant reserves at low costs. | |
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* 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. |
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* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $12 billion today. | |
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* Strategy built on the Formula: | |
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The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 4)
Recent
Developments
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* First Six Months of 2010 Highlights | ||
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* Net income of $293.9 million, up 19%(1).
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* Discretionary cash flow(2) of $763.5 million, up 9%.
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* Production of 188.3 Bcfe, up 36%.
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* Significant progress realized in our Fayetteville Shale play. | |
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* Gross operated production from Fayetteville Shale was approximately 1.45 Bcf per day in July 2010, up from 990 MMcf per day a year ago. |
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* Strong Growth and Low-Cost Operations Set the Stage for a Record 2010 | ||
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* 2010 planned capital investment program of approximately $2.1 billion, up 16% from 2009 levels. | |
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* 2010 gas and oil production projected to grow approximately 32% to 393 - 401 Bcfe. | |
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* Balance sheet positioned well for 2010, as of June 30, 2010: | |
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* Debt-to-book capital ratio of 31%; debt-to-market capitalization ratio of 9%. |
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* $1 billion credit facility with $506 million drawn at an average interest rate of 1.2%. |
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(1) |
Increase in net income is from first six months of 2009 adjusted net income of $246.6 million (a non-GAAP measure reconciled on page 29), which excludes a $558.3 million after-tax non-cash ceiling impairment. |
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(2) |
Discretionary cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure (see explanation and reconciliation on page 28). |
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Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 5)
Proven Track
Record
This slide contains bar charts for the periods ended December 31.
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2000 |
2001 |
2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
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Production (Bcfe) |
36 |
40 |
40 |
41 |
54 |
61 |
72 |
113 |
195 |
300 |
393-401E |
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Reserve Replacement (%) |
211% |
155% |
215% |
313% |
364% |
399% |
386% |
474% |
523% |
592% |
|
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EBITDA ($MM) (1) |
$104 |
$134 |
$99 |
$151 |
$255 |
$346 |
$415 |
$675 |
$1,362 |
$1,368 |
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F&D Cost ($/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 30.
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
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* 2009: |
3,657 Bcfe of Reserves |
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~100% Natural Gas |
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Production - 300.4 Bcfe |
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* 2010 Est. Production: 393-401 Bcfe | |
Conventional Arkoma
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* Reserves: 208 Bcf (6%) |
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* Production: 22.0 Bcf (7%) |
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* Net Acres: 338,486 (12/31/09) |
Fayetteville Shale
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* Reserves: 3,117 Bcf (85%) |
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* Production: 243.5 Bcf (81%) |
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* Net Acres: 888,695 (12/31/09) |
East Texas
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* Reserves: 330 Bcfe (9%) |
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* Production: 34.9 Bcfe (12%) |
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* Net Acres: 115,199 (12/31/09) |
Marcellus Shale
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* Net Acres: 150,800 (6/30/10) |
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* Southwestern's E&P segment operates in Arkansas, Texas, Oklahoma and Pennsylvania. |
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* Midstream Services segment provides marketing and gathering services for the E&P business. |
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Notes: |
2009 reserve data by area does not add to year-end totals for the company due to the exclusion of Marcellus Shale reserves. |
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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:
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2010 |
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2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
Plan |
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(in millions) |
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Corporate & Other |
$ 13 |
$ 16 |
$ 32 |
$ 16 |
$ 17 |
$ 29 |
$ 80 |
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Midstream Services |
$ - |
$ 16 |
$ 49 |
$ 107 |
$ 183 |
$ 214 |
$ 270 |
|
Drilling Rigs |
$ - |
$ 35 |
$ 94 |
$ 5 |
$ - |
$ - |
$ - |
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Property Acquisitions |
$ 14 |
$ - |
$ 18 |
$ 2 |
$ - |
$ 4 |
$ - |
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Cap. Expense & Other E&P |
$ 18 |
$ 32 |
$ 62 |
$ 77 |
$ 153 |
$ 190 |
$ 220 |
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Leasehold & Seismic |
$ 21 |
$ 61 |
$ 70 |
$ 166 |
$ 149 |
$ 114 |
$ 205 |
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Development Drilling |
$ 209 |
$ 287 |
$ 421 |
$ 1,110 |
$ 1,255 |
$ 1,254 |
$ 1,220 |
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Exploration Drilling |
$ 20 |
$ 36 |
$ 196 |
$ 20 |
$ 39 |
$ 4 |
$ 105 |
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Total |
$ 295 |
$ 483 |
$ 942 |
$ 1,503 |
$ 1,796 |
$ 1,809 |
$ 2,100 |
This slide also contains a pie chart of the company's planned 2010 capital investments by area of operation, summarized as follows:
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|
% of Total |
|
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Capital Investments |
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Arkoma Fayetteville Shale |
62% |
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Midstream |
13% |
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East Texas |
9% |
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Appalachia |
6% |
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New Ventures |
5% |
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Corp/Other |
4% |
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Arkoma |
1% |
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* E&P capital program heavily weighted to low-risk development drilling in 2010. | |
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* Plan to invest approximately $1.6 billion in the Fayetteville Shale play in 2010. | |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 8)
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.
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James Lime Horizontals | |
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52 Operated Wells | |
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Avg IP Rate - 9.0 MMcf/d | |
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Haynesville/Middle Bossier Horizontal Well IPs | |
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First Well: |
Completing |
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Second Well: |
WOC |
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Third Well: |
Drilling |
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CHK |
HK |
Other Wells |
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194 Wells |
93 Wells |
141 Wells |
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Avg IP: 11.8 MMcf/d |
Avg IP: 15.0 MMcf/d |
Avg IP: 8.2 MMcf/d |
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* Entered area in 2000 with purchase of 10,800 acres at Overton for $6.1 million. |
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* Current acreage position of 24,400 gross acres at Overton and 135,400 gross acres at Angelina. |
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* 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. |
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* Current 2010 capital program of $185 million, which includes participating in approximately 35 to 45 gross wells. |
Sources: Southwestern Energy Company, RBC Capital Markets
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 9)
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 and Price. Lines trace the Dominion, Tennessee Gas, Millennium and Stagecoach transmission pipelines.
Other test wells and areas are located on the map with their respective production data:
CHK
5 wells
Avg. Peak Rate
9.5 MMcf/d
RRC
>13.0 MMcf/d (2 hzls)
6.3 MMcf/d (vertical)
5.0 MMcf/d (vertical)
Other Test Wells
4.5 MMcf/d
4.0 MMcf/d
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* |
Currently hold approximately 151,000 net acres in Northeast Pennsylvania with Marcellus potential with an average lease term of 5 years, average royalty of 13% and average cost of approximately $600 per acre. |
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Drilling in 2010 with one operated rig in Greenzweig area and plan to participate in 30-35 wells, 20 of which are planned to be operated. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 10)
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 also denoted on the map.
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* SWN currently holds exploration licenses to over 2.5 million acres within the Maritimes Basin | |
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* Principal targets are the conventional and unconventional sandstone and shale reservoirs of the Horton Group | |
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* Oil and gas production from fields along southern flank: | |
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* McCully - reserves 190 bcfg |
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* Stoney Creek - cum 800,000 bo, 30 bcfg |
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* 3-year initial exploration license to complete work program | |
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* $47MM total work commitment with options for multiple 5-year extension leases |
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* Maximum 12.5% royalty |
(Slide 11)
Fayetteville
Shale Focus Area
This slide contains a map of the Fayetteville Shale Focus Area in Arkansas. Existing pilot areas and portions of the conventional fairway are indicated. 763,293 net acres and 125,400 net acres HBP are outlined on the map. The Ranger Anticline, Chattanooga Test and Moorefield Prospective Area are also denoted. Lines trace the Ozark, Centerpoint, Boardwalk, NGPL, MRT and TETCO transmission pipelines. Fayetteville Lateral Compression in-service January 2010.
* SWN currently holds 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 six months of 2010, we drilled and completed 249 operated wells, all of which were horizontal wells fracture stimulated with slickwater.
* We anticipate participating in 650-680 wells in 2010, 475-500 of which we plan to operate.
Notes: Data as of June 30, 2010.
Well data excludes 24 wells which were sold in May 2008.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 12)
Fayetteville
Shale - Improving Well Performance
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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 | ||||||
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1st Qtr 2007 |
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58 |
1,261 |
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1,066 |
(58) |
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958 |
(58) |
2,104 |
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2nd Qtr 2007 |
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46 |
1,497 |
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1,254 |
(46) |
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1,034 |
(46) |
2,512 |
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3rd Qtr 2007 |
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74 |
1,769 |
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1,510 |
(72) |
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1,334 |
(72) |
2,622 |
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4th Qtr 2007 |
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77 |
2,027 |
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1,690 |
(77) |
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1,481 |
(77) |
3,193 |
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1st Qtr 2008 |
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75 |
2,343 |
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2,147 |
(75) |
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1,943 |
(74) |
3,301 |
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2nd Qtr 2008 |
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83 |
2,541 |
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2,155 |
(83) |
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1,886 |
(83) |
3,562 |
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3rd Qtr 2008 |
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97 |
2,882 |
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2,560 |
(97) |
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2,349 |
(97) |
3,736 |
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4th Qtr 2008 |
(1) |
74 |
3,350 |
(1) |
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2,722 |
(74) |
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2,386 |
(74) |
3,850 |
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1st Qtr 2009 |
(1) |
120 |
2,992 |
(1) |
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2,537 |
(120) |
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2,293 |
(120) |
3,874 |
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2nd Qtr 2009 |
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111 |
3,611 |
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2,833 |
(111) |
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2,556 |
(111) |
4,123 |
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3rd Qtr 2009 |
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93 |
3,604 |
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2,640 |
(92) |
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2,275 |
(92) |
4,100 |
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4th Qtr 2009 |
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122 |
3,727 |
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2,674 |
(122) |
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2,360 |
(120) |
4,303 |
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1st Qtr 2010 |
(2) |
106 |
3,197 |
(2) |
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2,388 |
(106) |
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2,123 |
(106) |
4,348 |
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2nd Qtr 2010 |
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143 |
3,449 |
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2,610 |
(123) |
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2,431 |
(73) |
4,532 |
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* Focusing on longer laterals, slick-water completions and larger frac jobs. Average completed well cost for 2009 was $2.9 million. | |||||||||||
Note: Data as of June 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.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 13)
Fayetteville
Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through June 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 |
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0 |
1,367 |
1030 |
458 |
98 |
|
100 |
1,238 |
870 |
354 |
61 |
|
200 |
1,112 |
719 |
264 |
36 |
|
300 |
990 |
632 |
204 |
24 |
|
400 |
886 |
529 |
161 |
11 |
|
500 |
749 |
401 |
100 |
6 |
|
600 |
624 |
298 |
57 |
5 |
|
700 |
551 |
232 |
28 |
3 |
|
800 |
450 |
156 |
10 |
1 |
|
900 |
357 |
85 |
4 |
0 |
|
1000 |
280 |
34 |
1 |
0 |
|
1100 |
200 |
10 |
0 |
0 |
|
1200 |
146 |
3 |
0 |
0 |
|
1300 |
85 |
3 |
0 |
0 |
|
1400 |
43 |
3 |
0 |
0 |
|
1500 |
14 |
0 |
0 |
0 |
|
| ||||
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Note: Data as of June 30, 2010. Excludes wells with mechanical problems (28). | ||||
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 14)
Fayetteville
Shale - Gross Production
This slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to July 30, 2010. Gross operated production of approx. 1,447 MMcf/d as of July 30, 2010. 2009 Fayetteville Shale F&D cost of $0.69/Mcf. Periods of production affected by pipeline curtailment issues are denoted.
(Slide 15)
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.
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* |
Midstream assets provide rapidly growing revenue stream and potential future funding source. |
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* |
At August 2, 2010, gathering approximately 1,620 MMcf per day through 1,367 miles of gathering lines, up from approximately 1,060 MMcf per day the same time a year ago. |
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* |
2009 Midstream EBITDA(1) of $142 million and $180 - $185 million projected for 2010. |
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|
* |
Phase 1 Fayetteville Lateral of Boardwalk Pipeline placed in-service late December 2008. Phase 2 Greenville Lateral placed in-service April 2009. Phase 3 Fayetteville Lateral compression project placed in-service January 2010. |
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* |
Fayetteville Express Pipeline expected in-service late 2010 / early 2011 (FT volumes of 1,200,000 dkth/d). |
Note: Map as of June 30, 2010.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 30.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 16)
Outlook for
2010
* Production target of 393 - 401 Bcfe in 2010 (estimated growth of ~32%).
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2009 |
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2010 Guidance | ||
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Actual |
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NYMEX Price Assumptions(1) | ||
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$3.99 Gas |
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$4.00 Gas |
$5.00 Gas |
$6.00 Gas |
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$58.36 Oil |
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$80.00 Oil |
$80.00 Oil |
$80.00 Oil |
|
Adj. Net Income |
|
$522.7 MM(2) |
|
$555 - $565 MM |
$615 - $625 MM |
$690 - $700 MM |
|
Adj. Diluted EPS |
|
$1.52(2) |
|
$1.58 - $1.61 |
$1.76 - $1.79 |
$1.97 - $2.00 |
|
EBITDA(3) |
|
$1,368 MM |
|
$1,525 - $1,535 MM |
$1,630 - $1,640 MM |
$1,740 - $1,750 MM |
|
Net Cash Flow (3) |
|
$1,441 MM |
|
$1,505 - $1,515 MM |
$1,610 - $1,620 MM |
$1,720 - $1,730 MM |
|
CapEx |
|
$1,809 MM |
|
$2,100 MM |
$2,100 MM |
$2,100 MM |
|
Debt % |
|
30%(4) |
|
30% - 32% |
28% - 30% |
26% - 28% |
(1) 2010 guidance numbers include actual results through Q2 2010 and projected results based upon NYMEX price assumptions held flat for the balance of 2010.
(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. See explanation and reconciliation on page 29.
(3) 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 28 and 30.
(4) 2009 book capitalization includes the effect of the $558.3 million after-tax non-cash ceiling test impairment in the first quarter of 2009.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17)
The Road to
V+
|
* Invest in the Highest PVI Projects. | |
|
|
|
|
* Flexibility in 2010 Capital Program. | |
|
| |
|
* Maintain Strong Balance Sheet. | |
|
| |
|
* Deliver the Numbers. | |
|
|
* Production and Reserves. |
|
|
* Maximize Cash Flow. |
|
|
|
|
* Continue to Tell Our Story. | |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 18)
Appendix
(Slide 19)
Financial &
Operational Summary
|
|
Six Months Ended June 30, |
|
|
Year Ended December 31, |
| ||||||
|
|
2010 |
|
2009 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
($ in millions, except per share amounts) |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
$1,258.1 |
|
$1,018.3 |
|
|
$2,145.8 |
|
$2,311.6 |
|
$1,255.1 |
|
|
EBITDA (1) |
777.5 |
|
652.3 |
(3) |
|
1,368.1 |
(3) |
1,362.3 |
(2) |
675.4 |
|
|
Adjusted Net Income |
293.9 |
|
246.6 |
(3) |
|
522.7 |
(3) |
567.9 |
(2) |
221.2 |
|
|
Net Cash Flow (1) |
763.5 |
|
697.9 |
|
|
1441.0 |
|
1,167.5 |
|
651.2 |
|
|
Adjusted Diluted EPS |
$0.84 |
|
$0.71 |
(3) |
|
$1.52 |
(3) |
$1.64 |
(2) |
$0.64 |
(4) |
|
Diluted CFPS (1) |
$2.19 |
|
$2.04 |
|
|
$4.13 |
|
$3.37 |
|
$1.87 |
(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bcfe) |
188.3 |
|
138.2 |
|
|
300.4 |
|
194.6 |
|
113.6 |
|
|
Avg. Gas Price ($/Mcf) |
$4.82 |
|
$5.44 |
|
|
$5.30 |
|
$7.52 |
|
$6.80 |
|
|
Avg. Oil Price ($/Bbl) |
$75.87 |
|
$43.24 |
|
|
$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 28 and 30.
(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 29.
(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 |
30.0 Bcf |
$6.69 |
- |
|
|
Collars |
62.1 Bcf |
$5.09 / $6.50 |
- |
|
2012 |
Collars |
80.5 Bcf |
$5.50 / $6.67 |
- |
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).
|
|
|
Drillbit F&D 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)
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
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 23)
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 25-year period. Total Fayetteville Shale Field average daily production for March 2010 was 1,921 MMcf/d.
A box accompanying the graph states:
We collapsed the “learning curve” dramatically; Paradigm shift in gas prices
Source: Tudor, Pickering, Holt & Co. Securities, Inc., Arkansas Oil & Gas Commission
(Slide 24)
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 25)
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 26)
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 27)
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 28)
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.
|
|
6 Months Ended June 30, |
|
12 Months Ended December 31, | ||||||
|
|
2010 |
|
2009 |
|
2009 |
|
2008 |
|
2007 |
|
|
(in thousands) |
|
(in thousands) | ||||||
|
Net cash provided by operating activities |
$809,053 |
|
$673,731 |
|
$1,359,376 |
|
$1,160,809 |
|
$622,735 |
|
Add back (deduct): |
|
|
|
|
|
|
|
|
|
|
Change in operating assets and liabilities |
(45,558) |
|
24,120 |
|
81,652 |
|
6,685 |
|
28,435 |
|
Net cash flow |
$763,495 |
|
$697,851 |
|
$1,441,028 |
|
$1,167,494 |
|
$651,170 |
|
|
2010 Guidance | ||||
|
|
NYMEX Commodity Price Assumption | ||||
|
|
$4.00 Gas |
|
$5.00 Gas |
|
$6.00 Gas |
|
|
$80.00 Oil |
|
$80.00 Oil |
|
$80.00 Oil |
|
|
($ in millions) | ||||
|
Net cash provided by operating activities |
$1,505 - $1,515 |
|
$1,610 - $1,620 |
|
$1,720 - $1,730 |
|
Add back (deduct): |
|
|
|
|
|
|
Assumed change in operating assets and liabilities |
-- |
|
-- |
|
-- |
|
Net cash flow |
$1,505 - $1,515 |
|
$1,610 - $1,620 |
|
$1,720 - $1,730 |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 29)
Explanation and
Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income
Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
|
|
6 Months Ended |
|
12 Months Ended | ||||
|
|
June 30, 2009 |
|
December 31, 2009 | ||||
|
|
($ in thousands) |
|
(per share) |
|
($ in thousands) |
|
(per share) |
|
Net loss attributable to SWN |
$(311,730) |
|
$(0.91) |
|
$(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 |
246,575 |
|
$0.71 |
|
$522,655 |
|
$1.52 |
(Slide 30)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.
|
|
6 Months Ended June 30, |
|
|
12 Months Ended December 31, |
| |||||||||||||||||||||
|
|
2010 |
|
2009 |
|
|
2009 |
(1) |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
|
|
|
|
|
|
|
($ in thousands) |
| |||||||||||||||||||
|
Net income (loss) attributable to SWN |
$293,866 |
|
$(311,730) |
(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 |
12,688 |
|
6,750 |
|
|
18,638 |
|
|
28,904 |
|
23,873 |
|
679 |
|
15,040 |
|
16,992 |
|
17,311 |
|
21,466 |
|
23,699 |
|
24,689 |
|
|
Provision (benefit) for income taxes |
187,881 |
|
(192,687) |
(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 |
283,023 |
|
1,149,967 |
(4) |
|
1,401,470 |
(4) |
|
414,460 |
|
294,500 |
|
151,795 |
|
96,641 |
|
74,919 |
|
56,833 |
|
54,095 |
|
53,003 |
|
47,505 |
|
|
EBITDA |
$777,458 |
|
$652,300 |
|
|
$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, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2010, including current hedges in place:
|
|
|
2010 Guidance | |||||||
|
|
|
Overall Corporate |
|
|
| ||||
|
|
|
NYMEX Commodity Price Assumption |
|
|
Midstream | ||||
|
|
|
$4.00 Gas |
|
$5.00 Gas |
|
$6.00 Gas |
|
|
Services |
|
|
|
$80.00 Oil |
|
$80.00 Oil |
|
$80.00 Oil |
|
|
Segment (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to SWN |
|
$555 - $565 |
|
$615 - $625 |
|
$690 - $700 |
|
|
$80 - $84 |
|
Add back: |
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes |
|
355 - 361 |
|
393 - 399 |
|
441 - 447 |
|
|
49 - 52 |
|
Interest expense |
|
24 - 25 |
|
24 - 25 |
|
23 - 24 |
|
|
11 - 12 |
|
Depreciation, depletion and amortization |
|
585 - 590 |
|
585 - 590 |
|
585 - 590 |
|
|
38 - 39 |
|
EBITDA |
|
$1,525 - $1,535 |
|
$1,630 - $1,640 |
|
$1,740 - $1,750 |
|
|
$180 - $185 |
(1) Midstream Services segment results assume NYMEX commodity prices of $5.00 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".