Attached files
| file | filename |
|---|---|
| 8-K - SWN FORM 8-K INVESTOR PRESENTATION - SOUTHWESTERN ENERGY CO | swn010611form8k.htm |
EXHIBIT 99.1
Slide Presentation dated January 2011
(Cover)
Southwestern
Energy
January 2011 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 December 31, 2010
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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% |
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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
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Phone: |
(281) 618-4803 |
|
Fax: |
(281) 618-4820 |
Brad D. Sylvester, CFA
Vice President, Investor
Relations
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Phone: |
(281) 618-4897 |
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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
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* Focused on exploration and production of natural gas. | |
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* 3,657 Bcfe of reserves; 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 over $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 Nine Months of 2010 Highlights | ||
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* Net income of $454.6 million, up 25%(1). | |
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* Discretionary cash flow(2) of $1.2 billion, up 15%. | |
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* Production of 293.3 Bcfe, up 39%. | |
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* Significant progress realized in our Fayetteville Shale play. | |
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* Gross operated production from Fayetteville Shale was approximately 1.5 Bcf per day in October 2010, up from 1.2 Bcf per day a year ago. |
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* Current remaining inventory of over 9,000 wells on acreage drilled to date. |
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* Strong Growth and Low-Cost Operations Set the Stage for a Record 2011 | ||
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* 2011 planned capital investment program of approximately $1.9 billion, down 10% from 2010 projected levels. | |
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* 2011 gas and oil production projected to grow approximately 18% to 465 - 475 Bcfe. | |
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* One of the lowest cost operators in the industry – cash operating costs(3) of $1.31 per Mcfe in the third quarter of 2010. | |
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* Strong balance sheet and financial position as of September 30, 2010: | |
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* Debt-to-book capital ratio of 31%. |
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* $1 billion credit facility with $617 million drawn at an average interest rate of 0.9%. |
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(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. |
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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 32). |
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(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 ($0.06/Mcfe). |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 5)
Proven Track
Record
This slide contains bar charts for the periods ended December 31.
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2000 |
2001 |
2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
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Production (Bcfe) |
36 |
40 |
40 |
41 |
54 |
61 |
72 |
113 |
195 |
300 |
393-401E |
465-475E |
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Reserve Replacement (%) |
211% |
155% |
215% |
313% |
364% |
399% |
386% |
474% |
523% |
592% |
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EBITDA ($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 |
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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
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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 | |
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* 2011 Est. Production: 465-475 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: ~175,000 (12/31/10) |
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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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2011 |
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2005 |
2006 |
2007 |
2008 |
2009 |
2010E |
Plan |
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(in millions) | ||||||
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Corporate & Other |
$ 16 |
$ 32 |
$ 16 |
$ 17 |
$ 29 |
$ 80 |
$60 |
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Midstream Services |
$ 16 |
$ 49 |
$ 107 |
$ 183 |
$ 214 |
$ 270 |
$225 |
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Drilling Rigs |
$ 35 |
$ 94 |
$ 5 |
$ - |
$ - |
$ - |
$ - |
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Property Acquisitions |
$ - |
$ 18 |
$ 2 |
$ - |
$ 4 |
$ - |
$ - |
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Cap. Expense & Other E&P |
$ 32 |
$ 62 |
$ 77 |
$ 153 |
$ 190 |
$ 220 |
$255 |
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Leasehold & Seismic |
$ 61 |
$ 70 |
$ 166 |
$ 149 |
$ 114 |
$ 205 |
$195 |
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Development Drilling |
$ 287 |
$ 421 |
$ 1,110 |
$ 1,255 |
$ 1,254 |
$ 1,220 |
$1,151 |
|
Exploration Drilling |
$ 36 |
$ 196 |
$ 20 |
$ 39 |
$ 4 |
$ 105 |
$14 |
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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:
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% of Total |
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Capital Investments |
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Arkoma Fayetteville Shale |
60% |
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Appalachia |
14% |
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Midstream |
12% |
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New Ventures |
9% |
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Corp/Other |
3% |
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East Texas |
1% |
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Arkoma |
1% |
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* E&P capital program heavily weighted to low-risk development drilling in 2011. | |
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* Plan to invest approximately $1.4 billion in the Fayetteville Shale play in 2011. | |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 8)
Fayetteville
Shale Focus Area
This slide contains a map of the Fayetteville Shale Focus Area in Arkansas. Well locations for all wells drilled from inception of the play through Q3 2010 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, 3MMcf/d to 6MMcf/d and greater than 6MMcf/d. The Mississippi Embayment is also indicated on the map.
* At September 30, 2010, SWN held approximately 889,000 net acres in the Fayetteville Shale play area (equivalent to approximately 1,400 square miles).
* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.
* During the first nine months of 2010, SWN drilled and completed 394 operated wells, all of which were horizontal wells fracture stimulated with slickwater.
* We plan to drill approximately 440-450 operated wells in 2011.
Notes: Rates are AOGC Form 13 and Form 3 test rates.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 9)
Fayetteville
Shale – Continuous Improvement
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2007 |
2008 |
2009 |
2010 9M |
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Days to Drill |
17 |
14 |
12 |
12 |
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Lateral Length (in feet) |
2,657 |
3,619 |
4,100 |
4,472 |
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Well Cost ($ in millions) |
$2.9 |
$3.0 |
$2.9 |
$2.9 |
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F&D Cost ($ per Mcfe) |
$2.05 |
$1.21 |
$0.69 |
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Production (in Bcfe) |
53.5 |
134.5 |
243.5 |
251.4 |
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Reserves (in Bcfe) |
716 |
1,545 |
3,117 |
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* 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
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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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2,575 |
(141) |
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2,329 |
(141) |
4,532 |
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3rd Qtr 2010 |
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145 |
3,281 |
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2,439 |
(118) |
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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:
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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 |
1,482 |
1,155 |
554 |
134 |
|
100 |
1,347 |
999 |
452 |
99 |
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200 |
1,189 |
814 |
321 |
56 |
|
300 |
1,078 |
731 |
267 |
38 |
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400 |
960 |
617 |
209 |
25 |
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500 |
845 |
515 |
156 |
12 |
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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 |
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| ||||
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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.
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* |
Midstream assets provide rapidly growing revenue stream and potential future funding source. |
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* |
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. |
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* |
Midstream EBITDA(1) of $205 - $210 million projected for 2010. |
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* |
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). |
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* |
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.
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* |
At December 31, 2010, SWN held approximately 175,000 net acres in Northeast Pennsylvania with Marcellus Shale potential. |
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* |
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.
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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 (Frederick Brook Shale) | |
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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 16)
Outlook for
2011
* Production target of 465 - 475 Bcfe in 2011 (estimated growth of ~18%).
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2010 |
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2011 Guidance | ||
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Guidance(1) |
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NYMEX Price Assumptions | ||
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$4.00 Gas |
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$4.00 Gas |
$4.50 Gas |
$5.00 Gas |
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$80.00 Oil |
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$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 |
$1,900 MM |
|
Debt % |
|
28%-30% |
|
32%-34% |
30%-32% |
28%-30% |
(1) 2010 guidance numbers include actual results through Q3 2010 and projected results based upon NYMEX price assumptions held flat for the balance of 2010.
(2) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 32 and 34.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17)
The Road to
V+
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* Invest in the Highest PVI Projects. | |
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* Flexibility in 2011 Capital Program. | |
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| |
|
* Maintain Strong Balance Sheet. | |
|
| |
|
* Deliver the Numbers. | |
|
|
* Production and Reserves. |
|
|
* Maximize Cash Flow. |
|
|
|
|
* Continue to Tell Our Story. | |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 18)
Appendix
(Slide 19)
Financial &
Operational Summary
|
|
Nine Months Ended Sept. 30, |
|
|
Year Ended December 31, |
| ||||||
|
|
2010 |
|
2009 |
|
|
2009 |
|
2008 |
|
2007 |
|
|
|
($ 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
Source: Tudor, Pickering, Holt & Co. Securities, Inc., Arkansas Oil & Gas Commission
(Slide 25)
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 0.5% 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".