EXHIBIT 99.1
Slide Presentation dated August 11, 2008
The following slides were presented by Southwestern Energy Company.
(Cover)
Southwestern Energy Company
Presentation to The Oil & Gas Conference Sponsored by Enercom, Inc.
August 11, 2008
NYSE: SWN
The left side of this slide contains a picture of a helicopter flying over a mountain range at sunset. The caption above reads "The Right Balance." The company's formula
is located in the bottom corner. The top-right corner of this slide contains the company logo.
(Slide 1)
Southwestern Energy Company (NYSE: SWN)
General Information
Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production and natural gas gathering and marketing.
Market Data as of August 6, 2008
Shares of Common Stock Outstanding | 343,184,434 |
Market Capitalization | $12,011,000,000 |
Institutional Ownership | 91.1% |
Management Ownership | 4.0% |
52-Week Price Range* | $18.00 (8/28/07) - $48.53 (7/1/08) |
Investor Contacts
Greg D. Kerley
Executive Vice President and Chief Financial Officer
Phone: | (281) 618-4803 |
Fax: | (281) 618-4820 |
Brad D. Sylvester, CFA
Manager, Investor Relations
Phone: | (281) 618-4897 |
Fax: | (281) 618-4820 |
* As adjusted to reflect a two-for-one stock split effected on March 25, 2008.
(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 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 company's ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the impact of federal, state and local government regulation, including any increase in severance taxes; 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 and changes in interest rates, 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 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 Securities and Exchange Commission 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.
(Slide 3)
About Southwestern
| * Focused on domestic exploration and production of natural gas. |
| | * 1,450 Bcfe of reserves; 96% natural gas; 12.8 R/P at year-end 2007. |
| |
| * E&P strategy built on organic growth through the drillbit. |
| | * Over 80% of planned E&P capital allocated to drilling in 2008. |
| |
| * Track record of adding significant reserves at low costs. |
| | * From 2004 through 2007, we've averaged production growth of 28%, reserve growth of 31%, 418% reserve replacement, and F&D cost of $2.26 per Mcfe. |
| | |
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $12 billion. |
| * Strategy built on the Formula: |
| | 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
* Second Quarter 2008 Highlights |
| * Production of 45.1 Bcfe, up 74%. |
| * Net income of $136.6 million, up 187%. |
| * Discretionary cash flow of $288.2 million, up 96%. |
* Operations Update |
| * Arkoma Basin and East Texas development programs delivering high-return growth. |
| | * Early success with James Lime drilling program in East Texas. |
| * Significant progress realized in our Fayetteville Shale play. |
| | * Gross operated production from Fayetteville Shale project increased to approximately 500 MMcf per day at July 1, 2008, up from approximately 200 MMcf a year ago. |
| * Proceeds from recent asset sales position us well as we move into 2009. |
| | * As of July 1, 2008, we had completed the sale of , or had agreements to sell, non-core assets resulting in total gross proceeds of approximately $1 billion. |
Note: Discretionary cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure (see reconciliation on page 33).
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 5)
Proven Track Record
This slide contains bar charts for the periods ended December 31.
| | | | | | | | | | | |
| | 1999 | 2000 | 2001 | 2002 | 2003 | 2004 | 2005 | 2006 | 2007 | 2008E |
| Production (Bcfe) | 33 | 36 | 40 | 40 | 41 | 54 | 61 | 72 | 113 | 181-185E |
| Reserve Replacement (%) | 148% | 211% | 155% | 215% | 313% | 365% | 399% | 386% | 474% | |
| EBITDA ($MM) (1) | $75 | $104 | $134 | $99 | $151 | $255 | $346 | $415 | $675 | |
| F&D Cost ($/Mcfe) | $1.20 | $0.91 | $1.59 | $0.99 | $1.33 | $1.43 | $1.71 | $2.72 | $2.55 | |
Note: Reserve data includes reserve revisions and excludes capital investments in drilling rigs.
(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 New Mexico with shadings to denote the Conventional Arkoma and Permian Basins, the Gulf Coast and the East Texas regions and the Fayetteville Shale.
Exploration and Production Segment
* 2007: 1,450 Bcfe of Reserves |
| 96% Natural Gas |
| | Production: 113.6 Bcfe |
| * 2008 Est. Production: 181-185 Bcfe |
Conventional Arkoma
* Reserves - 304 Bcf (21%) |
| * Production - 23.8 Bcf (21%) |
Fayetteville Shale
* Reserves - 716 Bcf (49%) |
| * Production - 53.5 Bcf (47%) |
East Texas
* Reserves - 353 Bcfe (24%) |
* Production - 29.9 Bcfe (26%) |
Permian
* Reserves - 60 Bcfe (4%) |
* Production - 4.7 Bcfe (4%) |
Gulf Coast
* Reserves - 12 Bcfe (1%) |
* Production - 1.4 Bcfe (1%) |
* Southwestern's E&P segment operates in Arkansas, Texas, New Mexico, Oklahoma and Louisiana and generated approximately 95% of 2007 EBITDA. |
* Midstream Services segment provides marketing and gathering services for the E&P business. |
* Recently announced pending agreements to sell Permian Basin and Gulf Coast properties for approximately $250 million. |
Note: Reserve and production data by area does not add to year-end totals for Company due to exclusion of New Ventures 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:
| | | | | | | 2008 |
| 2003 | 2004 | 2005 | 2006 | 2007 | Plan |
| | (in millions) |
Utility & Other | $9 | $13 | $16 | $32 | $16 | $25 |
Property Acquisitions | $ - | $14 | $ - | $18 | $ 2 | $ - |
Cap. Expense & Other E&P | $12 | $18 | $32 | $62 | $77 | $142 |
Leasehold & Seismic | $19 | $21 | $61 | $70 | $166 | $131 |
Development Drilling | $120 | $209 | $287 | $421 | $1,110 | $1,218 |
Exploration Drilling | $20 | $20 | $36 | $196 | $20 | $50 |
| Midstream Services | $ - | $ - | $16 | $49 | $107 | $135 |
| Drilling Rigs | $ - | $ - | $35 | $94 | $ 5 | $ - |
Total | $180 | $295 | $483 | $942 | $1,503 | $1,701 |
This slide also contains a pie chart of the company's preliminary planned 2008 capital investments by area of operation, summarized as follows:
| % of Total |
| Capital Investments |
Arkoma Fayetteville Shale | 70% |
East Texas | 9% |
Arkoma | 8% |
| Midstream | 8% |
| Other E&P | 4% |
Corporate | 1% |
Utility/Other | <1% |
* E&P capital program heavily weighted to low-risk development drilling in 2008. |
| |
* Plan to invest over $1.3 billion in the Fayetteville Shale play in 2008. |
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. The company's Overton and Angelina River Trend acreage positions are highlighted. The James Lime Horizontals and the East Texas Salt Basin are also denoted on the map. The cities of Tyler and Lufkin, Texas are displayed as reference points.
| East Texas Activity: | | Annual | Year-End |
| Well | Production | Reserves |
| Count | (Bcfe) | (Bcfe) |
Original Wells (acquired) | 16 | 0.3 | 22 |
2001 - 2002 Development | 33 | 8.2 | 111 |
2003 Development | 57 | 13.6 | 196 |
2004 Development | 84 | 22.2 | 299 |
| 2005 Development | 88 | 28.2 | 369 |
2006 Development | 78 | 32.0 | 383 |
2007 Development | 80 | 29.9 | 353 |
Planned 2008 Development | 55 | 29 - 31 | |
James Lime Horizontals |
9 Wells Completed |
Avg IP Rate - 8.0 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 102,000 gross acres at Angelina and Jebel. |
|
* 2008 development program includes approximately 21 net James Lime horizontal wells. |
|
* Announced a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale intervals (approximately 41,500 gross acres in 3 counties). |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 9)
Arkoma Basin
This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin. The Fayetteville Shale Focus Area, Ranger Anticline, Midway and the area known as the Fairway are further noted.
| * 65+ years of experience in the basin, large acreage position of over 490,000 net acres in the traditional fairway. |
| | * 2008 capital program includes drilling 100 - 110 wells in the traditional fairway, Ranger Anticline and Midway areas. |
| |
* SWN currently holds approximately 857,000 net acres in the Fayetteville Shale play area (equivalent to over 1,300 square miles). |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 10)
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. 731,600 net acres and 125,400 net acres HBP are outlined on the map. A box denotes Conventional Production (12 MMcf/d). The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Chattanooga Test and Ranger Anticline are also designated. The Moorefield Prospective Area is outlined. Lines trace the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines.
* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas. |
|
* As of June 30, 2008, SWN has drilled and completed 619 wells, of which 507 are horizontal slickwater or crosslinked gel fracture stimulated wells, in 33 separate pilot areas in 8 counties. |
| |
* We anticipate participating in 520 horizontal wells in 2008, approximately 75% operated. |
Notes: Map updated as of May 8, 2008.
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 11)
Fayetteville Shale - Improving Well Performance
| Time Frame | Wells Placed on Production | Average IP Rate (Mcf/d) | 30th-Day Avg Rate (# of wells) | 60th-Day Avg Rate (# of wells) | Avg Lateral Length | Completion Method SW/XL/Hy-RHy |
| 1st Qtr 2007 | 58 | 1,261 | 1,066 (58) | 958 (58) | 2,104 | 11/37/10 |
| 2nd Qtr 2007 | 46 | 1,497 | 1,254 (46) | 1,034 (46) | 2,512 | 24/12/10 |
| 3rd Qtr 2007 | 74 | 1,788 | 1,512 (72) | 1,350 (71) | 2,622 | 69/4/1 |
| 4th Qtr 2007 | 77 | 2,028 | 1,690 (77) | 1,499 (76) | 3,193 | 68/1/8 |
| 1st Qtr 2008 | 75 | 2,343 | 2,147 (75) | 1,930 (72) | 3,301 | 71/1/3 |
| 2nd Qtr 2008 | 83 | 2,541 | 2,143 (58) | 1,798 (26) | 3,562 | 83/0/0 |
|
* Focusing on longer laterals, slick-water completions and larger frac jobs. |
|
* For the remainder of 2008, the average lateral length of planned wells is projected to be approximately 3,600 feet and our average well cost is projected to be $3.0 million. |
|
* Utilizing 3-D seismic to improve overall well performance. Over 75% of our 2008 planned wells will have the benefit of 3-D seismic (versus 20% in 2007). |
Note: Data as of June 30, 2008.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 12)
Fayetteville Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through June 30, 2008, for the company's horizontal wells drilled in the Fayetteville Shale. This graph displays two composite curves, one showing the SW/XL normalized production from the company's horizontal wells excluding mechanical issues and another showing the SW normalized production from the company's horizontal wells with laterals greater than 3,000 feet excluding mechanical issues. The production data is compared to 2.5 Bcf, 2.0 Bcf and 1.5 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 | All Horizontal Wells with Laterals > 3,000 Feet |
| | | |
| 30 | 446 | 182 |
| 60 | 416 | 154 |
| 90 | 390 | 132 |
| 120 | 367 | 114 |
| 150 | 331 | 87 |
| 180 | 320 | 77 |
| 210 | 296 | 63 |
| 240 | 279 | 53 |
| 270 | 253 | 32 |
| 300 | 228 | 24 |
| 330 | 204 | 18 |
| 360 | 182 | 11 |
| 390 | 165 | 8 |
| 420 | 145 | 4 |
| 450 | 136 | 2 |
| 480 | 117 | 2 |
| 510 | 95 | 2 |
| 540 | 82 | 2 |
| 570 | 66 | 2 |
| 600 | 48 | 2 |
| 630 | 40 | 2 |
| 660 | 34 | 2 |
| 690 | 28 | 1 |
| 720 | 21 | 1 |
| 750 | 13 | 0 |
| 780 | 7 | 0 |
| 810 | 4 | 0 |
| 840 | 2 | 0 |
| 870 | 1 | 0 |
| 900 | 1 | 0 |
| 930 | 1 | 0 |
| 960 | 1 | 0 |
| 990 | 1 | 0 |
Note: Data as of June 30, 2008.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 13)
Fayetteville Project - Gross Production
This line graph shows gross production in MMcf/d for the Fayetteville Shale from January 2006 to July 1, 2008. Gross operated production of approx. 500 MMcf/d as of July 1, 2008.
(Slide 14)
Midstream - Capturing Additional 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, Transmission, Planned Boardwalk Lateral and the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines. Compression facilities are also indicated on the map.
* Midstream assets provide rapidly growing revenue stream and potential future funding source. |
|
* Currently gathering approximately 600 MMcf per day through 736 miles of gathering lines, up from approximately 224 MMcf per day the same time a year ago. |
| |
* 2007 EBITDA(1) of $18.8 million and $55.0 to $60.0 million projected for 2008. Projected capex of $135 million for 2008. |
Note: Map updated as of May 8, 2008.
(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 15)
Outlook for 2008
* Production target of 181 - 185 Bcfe in 2008 (estimated growth of ~60%).
| | 2007 | | 2008 Guidance |
| | Actual | | NYMEX Price Assumptions |
| | $6.86 Gas | | $8.00 Gas | | $9.00 Gas | | $10.00 Gas |
| | $69.72 Oil | | $80.00 Oil | | $90.00 Oil | | $100.00 Oil |
| | | | | | | | |
| Net Income | $221.2 MM | | $485 - $490 MM | | $515 - $520 MM | | $550 - $555 MM |
| EPS | $0.64 (1) | | $1.38 - $1.42 | | $1.47 - $1.51 | | $1.56 - $1.60 |
| EBITDA (2) | $675.4 MM | | $1,235 - $1,245 MM | | $1,285 - $1,295 MM | | $1,335 - $1,345 MM |
| Net Cash Flow (2) | $651.2 MM | | $1,090 - $1,100 MM | | $1,140 - $1,150 MM | | $1,190 - $1,200 MM |
| Divestitures (3) | --- | | $1 Billion | | $1 Billion | | $1 Billion |
| CapEx | $1,503 MM | | $1,701 MM | | $1,701 MM | | $1,701 MM |
| Debt % | 37% | | 25% - 26% | | 25% - 26% | | 25% - 26% |
Note: Guidance updated as of August 6, 2008. 2007 oil and gas prices include actual last-day NYMEX closing prices through July 2008.
(1) As adjusted to reflect the two-for-one stock split effected on March 25, 2008.
(2) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 33 and 34.
(3) Expected gross proceeds of asset divestitures (includes sale of utility, Fayetteville Shale acreage, and planned sale of Permian Basin and Gulf Coast assets).
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 16)
The Road to V+
| * Invest in the Highest PVI Projects. |
| | |
| * Accelerate Development of the Fayetteville Shale Play. |
| |
| * Deliver the Numbers. |
| | * Production and Reserve Growth. |
| | * Maximize Cash Flow. |
| | |
| * Continue to Tell Our Story. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17)
Appendix
(Slide 18)
Financial & Operational Summary
| | Six Months Ended June 30, | | Year Ended December 31, | |
| | 2008 | 2007 | | 2007 | 2006 | 2005 | |
| | ($ in millions, except per share amounts) | |
| | | | | | | | |
| Revenues | $1,128.5 | $554.7 | | $1,255.1 | $763.1 | $676.3 | |
| EBITDA (1) | 612.2 | 288.0 | | 675.4 | 414.5 | 345.9 | |
| Net Income | 245.6 | 98.6 | | 221.2 | 162.6 | 147.8 | |
| Net Cash Flow (1) | 571.9 | 289.2 | | 651.2 | 413.5 | 321.8 | |
| Diluted EPS (2) | $0.71 | $0.29 | | $0.64 | $0.47 | $0.47 | |
| Diluted CFPS (2) | $1.65 | $0.84 | | $1.87 | $1.21 | $1.03 | |
| | | | | | | | |
| Production (Bcfe) | 84.1 | 48.7 | | 113.6 | 72.3 | 61.0 | |
| Avg. Gas Price ($/Mcf) | $7.95 | $6.81 | | $6.80 | $6.55 | $6.51 | |
| Avg. Oil Price ($/Bbl) | $108.69 | $58.42 | | $69.12 | $58.36 | $42.62 | |
| | | | | | | | |
| Finding Cost ($/Mcfe) (3) | | | | $2.55 | $2.72 | $1.71 | |
| Reserve Replacement (%) (3) | | | | 474% | 386% | 399% | |
(1) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and EBITDA are non-GAAP financial measures. See explanation and reconciliation of non-GAAP financial measures on pages 33 and 34.
(2) Diluted earnings per share and diluted cash flow per share have been adjusted to reflect the two-for-one stock split effected on March 25, 2008 and two 2-for-1 stock splits during 2005.
(3) Includes reserve revisions and excludes capital investments in drilling rigs.
(Slide 19)
Consistent Commodity Hedging Strategy
This slide contains a bar chart detailing gas hedges in place by quarter for year 2008, year 2009 and year 2010. A summary of these gas hedges is as follows:
| | | Average Price per Mcf | Percent |
| Type | Hedged Volumes | (or Floor/Ceiling) | Hedged |
2008 | Swaps | 70.0 Bcf | $8.43 | 39% |
| Collars | 48.0 Bcf | $7.92 / $11.60 | 27% |
2009 | Swaps | 76.0 Bcf | $8.30 | - |
| Collars | 59.0 Bcf | $8.71 / $11.69 | - |
2010 | Swaps | 36.0 Bcf | $9.04 | - |
| Collars | 14.0 Bcf | $8.29 / $10.57 | - |
SWN has historically hedged 70 - 80% of projected gas production volumes.
Historical Gas Hedge Percentages | |
| 2002 | 78% | |
| 2003 | 80% | |
| 2004 | 70% | |
| 2005 | 79% | |
| 2006 | 73% | |
| 2007 | 72% | |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 20)
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 | | $0.88 |
| Noble Energy | | $1.12 |
Chesapeake Energy | | $1.16 |
Ultra Petroleum | | $1.17 |
EOG Resources | | $1.19 |
| EnCana | | $1.23 |
| Range Resources | | $1.24 |
Pioneer Natural Resources | | $1.37 |
Devon Energy | | $1.53 |
| XTO Energy | | $1.54 |
Newfield Exploration | | $1.60 |
| Forest Oil | | $1.63 |
Cimarex Energy | | $1.73 |
| Cabot Oil & Gas | | $1.75 |
Anadarko Petroleum | | $1.77 |
| Apache | | $1.78 |
| Quicksilver Resources | | $1.84 |
| St. Mary Land & Exploration | | $1.87 |
| Swift Energy | | $1.88 |
| Denbury Resources | | $2.56 |
This slide also contains a bar graph comparing SWN to its competitors in terms of drillbit F&D cost per Mcfe (3 year average).
| | | Drillbit F&D Cost |
| | | per Mcfe |
| | | (3 year average) |
| | | |
| Ultra Petroleum | | $0.75 |
| Quicksilver Resources | | $1.15 |
XTO Energy | | $1.67 |
Range Resources | | $1.89 |
| Cabot Oil & Gas | | $1.99 |
| EOG Resources | | $2.10 |
| EnCana | | $2.12 |
Southwestern Energy Company | | $2.21 |
Devon Energy | | $2.44 |
| Apache | | $2.53 |
Denbury Resources | | $2.92 |
Newfield Exploration | | $3.08 |
Forest Oil | | $3.66 |
Noble Energy | | $4.09 |
| St. Mary Land & Exploration | | $4.30 |
| Pioneer Natural Resources | | $4.41 |
Cimarex Energy | | $4.42 |
| Swift Energy | | $6.08 |
Anadarko Petroleum | | $6.09 |
Chesapeake Energy | | $6.18 |
Source: John S. Herold Database
Note: All data as of December 31, 2005, 2006 and 2007.
Drillbit F&D Cost per Mcfe defined as three-year sum of total costs incurred less the three-year sum of proved acquisitions cost divided by the three-year sum of reserve additions from extensions and discoveries.
(Slide 21)
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. 40 Vertical Wells/Year | |
| | |
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1995-1999 | Avg. 73 Vertical Wells/Year | |
| | |
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2000 | Vertical Wells Drilled Horizontal Wells Drilled | 186 2 | |
| | |
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2001 | Vertical Wells Drilled Horizontal Wells Drilled | 501 3 | |
| | |
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2002 | Vertical Wells Drilled Horizontal Wells Drilled | 785 5 | |
| | |
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2003 | Vertical Wells Drilled Horizontal Wells Drilled | 872 75 | |
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2004 | Vertical Wells Drilled Horizontal Wells Drilled | 566 278 | |
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2005 | Vertical Wells Drilled Horizontal Wells Drilled | 322 613 | |
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2006 | Vertical Wells Drilled Horizontal Wells Drilled | 273 1,189 | |
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2007 | Vertical Wells Drilled Horizontal Wells Drilled | 185 2,442 | |
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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 | 21 0 | |
| | |
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2005 | Vertical Wells Drilled Horizontal Wells Drilled | 32 40 | |
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2006 | Vertical Wells Drilled Horizontal Wells Drilled | 8 205 | |
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2007 | Vertical Wells Drilled Horizontal Wells Drilled | 8 504 | |
| | |
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2008E | Vertical Wells Drilled Horizontal Wells Drilled | 0 ~1,000 | |
| | |
Source: Republic Energy Co., Tudor, Pickering, Holt & Co. Securities, Inc., Arkansas Oil & Gas Commission via PI-Dwights, Southwestern Energy
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 22)
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 less than 4-year period and the Barnett Shale over a more than 20-year period. It is noted that the total Fayetteville Shale Field average daily production for March 2008 was 564 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 23)
The Energy Balance Today
* Oil and gas prices have risen substantially since 2002. |
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* World demand for hydrocarbons has increased dramatically (China, India, etc.) and supply/demand relationship is tight. |
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* Resource nationalism is a reality. |
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| * A serious challenge exists to meet demand growth for hydrocarbons (oil and gas). |
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| * There are no "silver bullet" technologies today to replace hydrocarbons. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 24)
U.S. Oil Consumption and Sources
This slide displays U.S. oil production versus U.S. oil consumption in thousands of barrels per year from 1981 to 2006. Net imports for the same period are also given. Imports represent 66% of total US consumption.
Source: EIA
(Slide 25)
West Texas Intermediate Oil Prices
This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to present noting a compound average growth rate of 30% from 2002 to 2008. It is also noted, however, finding costs for US E&P Companies from 2002-2007 grew at a 26% CAGR.
Source: Bloomberg, John S. Herold, Inc.
(Slide 26)
Rising Resource Nationalism
This slide contains a bar graph displaying the volume of oil and gas resources in BBoe controlled by the following entities:
Government-owned Oil Companies (GOCs) –95%:
Saudi Aramco, NIOC (Iran), Qatar Petroleum, ADNOC (UAE), Iraq NOC,
Gazprom (Russia), KPC (Kuwait), PDVSA (Venezuela), NNPC (Nigeria), NOC (Libya)
Sonatrach (Algeria), Rosneft (Russia), Petronas (Malaysia), Lukoil (Russia),
Pemex (Mexico), Petrochina (China), Petrobras (Brazil), ONGC (India), Sinopec (China)
International Oil Companies (IOCs) –5%:
ExxonMobil, BP, Chevron, Royal Dutch Shell, Total, ConocoPhillips, ENI
* GOCs control an overwhelming majority of oil and gas resources.
Source: Merrill Lynch
(Slide 27)
The Challenges
* Aging of the workforce |
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* Access to land |
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* Political situations in large resource countries |
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| * Balancing environmental vs. energy needs |
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| * Lack of new talent (engineering and technical) |
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| * Challenge of meeting the demand growth with new supplies |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 28)
U.S. Gas Consumption and Sources
This slide displays U.S. gas production versus U.S. gas consumption in Bcf from 1975 to 2006. Net imports for the same period are also given. U.S. gas consumption and production rising in recent years.
Source: EIA
(Slide 29)
U.S. Electricity Consumption on the Rise
This line graph shows an increase in U.S. electricity consumption in billion kilowatt-hours per month from 1990 to present.
Source: Edison Electric Institute
(Slide 30)
NYMEX Gas Prices
This line graph represents NYMEX gas prices in $/Mcf from 2000 to present.
Source: Bloomberg
(Slide 31)
U.S. Gas Drilling
This line graph denotes the number of rigs drilling for gas through the period 1988 to present.
Source: Baker Hughes
(Slide 32)
Oil and Gas Price Comparison
This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1994 to present.
Source: Bloomberg
(Slide 33)
Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow
Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misl eading. Therefore, the reconciliation of the company’s forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities. The first table below reconciles actual net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.
| | 6 Months Ended June 30, | | Year Ended December 31, |
| | 2008 | | 2007 | | 2007 | | 2006 | | 2005 |
| | ($ in thousands) |
Net cash provided by operating activities before changes in operating assets and liabilities | $571,947 | | $289,186 | | $651,170 | | $413,508 | | $321,758 |
Add back (deduct): | | | | | | | | | |
Change in operating assets and liabilities | 16,305 | | (30,968) | | (28,435) | | 16,429 | | (17,276) |
Net cash provided by operating activities | $588,252 | | $258,218 | | $622,735 | | $429,937 | | $304,482 |
| | | 2008 Guidance |
| | | NYMEX Commodity Price Assumptions |
| | | $8.00 Gas | | $9.00 Gas | | $10.00 Gas |
| | | $80.00 Oil | | $90.00 Oil | | $100.00 Oil |
| | ($ in millions) |
| Net cash provided by operating activities | | $1,090-$1,100 | | $1,140-$1,150 | | $1,190-$1,200 |
| Add back (deduct): | | | | | | |
| Assumed change in operating assets and liabilities | | -- | | -- | | -- |
Net cash provided by operating activities before changes in operating assets and liabilities | | $1,090-$1,100 | | $1,140-$1,150 | | $1,190-$1,200 |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 34)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.
| 6 Months Ended June 30, | | 12 Months Ended December 31, | |
| 2008 | | 2007 | | 2007 (1) | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | | 2000 | | 1999 | |
| | ($ in thousands) | |
Net income | $245,579 | | $98,582 | | $221,174 | | $162,636 | | $147,760 | | $103,576 | | $48,897 | | $14,311 | | $35,324 | | $20,461 | (2) | $9,927 | |
Depreciation, depletion and amortization | 195,559 | | 122,495 | | 294,500 | | 151,795 | | 96,641 | | 74,919 | | 56,833 | | 54,095 | | 53,003 | | 47,505 | | 41,707 | |
Net interest expense | 20,526 | | 6,464 | | 23,873 | | 679 | | 15,040 | | 16,992 | | 17,311 | | 21,466 | | 23,699 | | 24,689 | | 17,351 | |
Provision for income taxes | 150,517 | | 60,421 | | 135,855 | | 99,399 | | 86,431 | | 59,778 | | 28,372 | (3) | 8,708 | | 21,917 | | 11,457 | | 6,449 | |
EBITDA | $612,181 | | $287,962 | | $675,402 | | $414,509 | | $345,872 | | $255,265 | | $151,413 | | $98,580 | | $133,943 | | $104,112 | (2) | $75,434 | |
(1) Net income for the Midstream Services segment was $6,933, depreciation, depletion and amortization was $5,527, net interest expense was $2,006 and provision for income taxes was $4,294.
(2) 2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.
(3) Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.
The table below reconciles forecasted EBITDA with forecasted net income for 2008, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2008, including current hedges in place, as of August 5, 2008:
| | | 2008 Guidance |
| | | Overall Corporate | | |
| | | NYMEX Commodity Price Assumptions | | Midstream |
| | | $8.00 Gas | | $9.00 Gas | | $10.00 Gas | | Services |
| | | $80.00 Oil | | $90.00 Oil | | $100.00 Oil | | Segment (1) |
| | | ($ in millions) | | |
| Net income | | $485-$490 | | $515-$520 | | $550-$555 | | $26-$28 |
| Add back: | | | | | | | | |
| Provision for income taxes | | 297-300 | | 316-319 | | 337-340 | | 16-17 |
| Interest expense | | 38-39 | | 38-39 | | 38-39 | | 3-5 |
| Depreciation, depletion and amortization | | 410-415 | | 410-415 | | 410-415 | | 10-12 |
| EBITDA | | $1,235-$1,245 | | $1,285-$1,295 | | $1,335-$1,345 | | $55-$60 |
(1) Midstream Services segment 2008 results assumes NYMEX commodity prices of $9.00 per Mcf for natural gas and $90.00 per barrel for crude oil.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
