Attached files
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| 8-K - SWN FORM 8-K AUGUST 2013 INVESTOR PRESENTATION - SOUTHWESTERN ENERGY CO | swn080513form8k.htm |
EXHIBIT 99.1
Slide Presentation dated August 2013
(Cover)
Southwestern Energy
August 2013 Update
NYSE: SWN
The upper left side of this slide contains a SWN employee assisting with a volunteer project. The upper right side of this slide contains a scenic view of the Marcellus countryside. The bottom left side of this slide contains a drilling rig operating in the Marcellus Shale play. The bottom right side of this slide contains a compressed natural gas (CNG) station with a price of $1.60 gallon of gas equivalent (GGE) located in Damascus, Arkansas.
(Slide 1)
Southwestern Energy Company
General Information
Southwestern Energy Company is an independent 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 1, 2013
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NYSE: SWN |
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Shares of Common Stock Outstanding |
351,512,483 |
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Market Capitalization |
$14,029,000,000 |
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Institutional Ownership |
92.7% |
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Management and Board Ownership |
2.0% |
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52-Week Price Range |
$30.55 (8/6/12) - $39.91 (8/1/13) |
Investor Contacts
Steve Mueller
President and Chief Executive Officer
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Phone: |
(281) 618-4800 |
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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 facts and financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company’s ability to fund the company’s planned capital investments; the company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play overall as well as relative to other productive shale gas plays; the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives; the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s future property acquisition or divestiture activities; the impact of the adverse outcome of any material litigation against the company; the effects of weather; increased competition and regulation; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
The SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.
The contents of this presentation are current as of August 1, 2013.
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* Focused on exploration and production of natural gas. |
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* 4.0 Tcfe of reserves; 7.1 R/P at year-end 2012. |
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* E&P strategy built on organic growth through the drillbit. |
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* Over 70% of planned E&P capital allocated to drilling in 2013. |
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* Track record of adding significant reserves at low costs. |
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* From 2007 to 2012, we’ve averaged 38% annual production growth and 23% reserve growth and annually replaced over 325% of our production at an F&D cost of $1.36 per Mcfe(1). |
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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+. |
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(1) |
Reserve replacement ratio and finding and development costs exclude reserve revisions and capital investment in our sand facility, drilling rig related and ancillary equipment. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 4)
Second Quarter 2013 Highlights
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* Second Quarter 2013 Highlights |
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* Production up 17%, due to strong Fayetteville and Marcellus results. |
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* Recorded highest quarterly adjusted earnings, EBITDA (1) and discretionary cash flow (1) in company history, primarily driven by low cash operating costs (2) and the continued strong growth from our Midstream business. |
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* Currently active on more than 5 New Ventures projects with over 1.3 million exploration acres. |
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* Strong balance sheet and financial position as of June 30, 2013: |
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* Debt-to-book capitalization ratio of 36% |
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* $1.5 billion revolving credit facility with $230 million drawn. |
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* Cash and restricted cash on hand of approximately $26 million |
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* Strong Growth and Low-Cost Operations Set the Stage for a Record 2013 |
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* 2013 projected capital investment program of $2.25 billion. |
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* 2013 production projected to grow 15%. |
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(1)
(2) |
EBITDA and discretionary cash flow are non-GAAP financial measures.
Cash operating costs for the six months ended June 30, 2013 include lease operating expenses ($0.83/Mcfe), general and administrative expenses ($0.23/Mcfe), taxes other than income taxes ($0.11/Mcfe) and net interest expense ($0.06/Mcfe). |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
This slide contains bar charts for the periods ended December 31.
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2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
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Production (Bcfe) |
40 |
41 |
54 |
61 |
72 |
113 |
195 |
300 |
405 |
500 |
565 |
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Average Realized Gas Price ($/Mcf) |
$ 3.00 |
$ 4.20 |
$ 5.21 |
$ 6.51 |
$ 6.55 |
$ 6.80 |
$ 7.52 |
$ 5.30 |
$ 4.64 |
$ 4.19 |
$ 3.44 |
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Proved Reserves (Bcfe) |
415 |
503 |
646 |
827 |
1,026 |
1,450 |
2,185 |
3,657 |
4,937 |
5,893 |
4,018 |
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EBITDA ($MM)(1) |
$ 99
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$ 151
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$ 255
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$ 346
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$ 415
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$ 675
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$ 1,362
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$ 1,368
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$ 1,612
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$ 1,775 |
1,638 |
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F&D Cost ($/Mcfe) (2) |
$ 1.01
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$ 1.18
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$ 1.34
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$ 1.51
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$ 2.08
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$ 2.70
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$ 1.70
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$.91 |
$ 1.24
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$ 1.34 |
$ 2.08 |
Note: Reserve data includes reserve revisions.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 35.
(2) Excludes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(Slide 6)
Areas of Operations
This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and Pennsylvania with shadings to denote the Ark-La-Tex region, the Fayetteville Shale and the Marcellus Shale.
Exploration & Production Segment
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* 2012: |
4,018 Bcfe of Reserves |
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Production – 565.0 Bcfe |
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* 2013 Est. Production: 643-651 Bcfe |
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New Ventures
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* Brown Dense – Approx. 507,000 net acres |
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* Colorado – Approx. 302,000 net acres |
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* New Brunswick – Approx. 2.5 million acres |
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* Undisclosed Ventures – Approx. 495,000 net acres |
Fayetteville Shale
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* Reserves: 2,988 Bcf (75%) |
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* Production: 485.5 Bcf (86%) |
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* Net Acres: 913,502 (12/31/12) |
Ark-La-Tex
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* Reserves: 213 Bcfe (5%) |
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* Production: 25.6 Bcfe (5%) |
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* Net Acres: 163,627 (12/31/12) |
Marcellus Shale
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* Reserves: 816 Bcf (20%) |
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* Production: 53.6 Bcf (9%) |
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* Net Acres: 337,300 (4/30/13) |
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*Southwestern’s E&P segment operates in Arkansas, Texas, Pennsylvania, Louisiana, Oklahoma, and New Brunswick. |
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* Midstream Services segment provides marketing and gathering services for the E&P business. |
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ArkLaTex acreage excludes 124,563 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area. Reserves and acreage as of December 31, 2012. Production is a total annual amount for 2012. |
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 (in $ Millions):
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2013 |
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2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
Forecast |
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Corporate & Other |
$ 32
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$ 16
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$ 17
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$ 30
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$ 73
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$ 69
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$ 55
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$ 90
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Midstream Services |
49 | 107 | 183 | 214 | 271 | 161 | 165 | 160 |
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Drilling Rigs |
94 | 5 |
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Property Acquisitions |
18 | 2 |
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1 |
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93 |
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Cap. Expense & Other E&P |
62 | 77 | 153 | 190 | 185 | 220 | 269 | 321 |
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Leasehold & Seismic |
70 | 166 | 149 | 114 | 215 | 257 | 196 | 129 |
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Development Drilling |
421 | 1,110 | 1,255 | 1,257 | 1,370 | 1,486 | 1,257 | 1,387 |
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Exploration Drilling |
196 | 20 | 39 | 4 | 5 | 14 | 139 | 70 |
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Total |
$ 942
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$ 1,503
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$ 1,796
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$ 1,809
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$ 2,120
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$ 2,207
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$ 2,081
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$ 2,250
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Additionally, this slide contains a pie chart of the company's planned 2012 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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Fayetteville Shale |
40% |
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Marcellus |
39% |
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Midstream |
7% |
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New Ventures |
10% |
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Corp/Other |
4% |
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Ark-La-Tex |
1% |
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* E&P capital program heavily weighted to low-risk development drilling in 2013. |
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* Plan to invest approximately $980 million in the Fayetteville Shale and $950 million in the Marcellus Shale (including Midstream and recent acreage acquisition) in 2013. |
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Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 8)
Marcellus Shale
This slide contains a map of several counties in Pennsylvania and New York. The company's acreage positions are highlighted. This chart also notes planned wells in 2013 for Lycoming County (8 wells), Bradford County (37 wells), and Susquehanna County (55 wells). Lines trace the Transco, Tennessee Gas, Millennium, Stagecoach, PVR Line, and Bluestone transmission pipelines.
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We hold approximately 337,300 net acres in Northeast Pennsylvania. |
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At June 30, 2013, our gross operated production from the Marcellus Shale was approximately 503 MMcf/d from 129 operated horizontal wells. |
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We plan to drill up to 100 operated wells in 2013. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 9)
Marcellus Gross Production by County
The large graph contained in this slide provides daily production data for wells located in Bradford County, Lycoming County and Susquehanna County with the ending well count of 72, 49 and 8 for each county respectively. The small table contained in this slide contains quarterly drilling statistics as follows:
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Time Period |
30th Day Avg. Rate (# of Wells) |
Average of CLAT (ft) |
Avg RE-RE (Rig Days) |
Avg CWC ($MM) |
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2010 3rd Qtr |
1,405 |
(1) |
2,927 |
22.6 |
$5.8 |
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2010 4th Qtr |
5,584 |
(6) |
3,805 |
19.8 |
$7.1 |
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2011 1st Qtr |
5,052 |
(3) |
3,864 |
18.1 |
$6.6 |
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2011 2nd Qtr |
6,114 |
(7) |
4,780 |
13.4 |
$6.7 |
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2011 4th Qtr |
5,284 |
(5) |
4,129 |
18.8 |
$6.0 |
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2012 1st Qtr |
7,327 |
(2) |
4,009 |
13.2 |
$6.0 |
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2012 2nd Qtr |
3,859 |
(17) |
3,934 |
12.9 |
$6.0 |
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2012 3rd Qtr |
4,493 |
(8) |
4,380 |
13.2 |
$5.7 |
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2012 4th Qtr |
4,606 |
(22) |
3,830 |
15.9 |
$7.0 |
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2013 1st Qtr |
5,356 |
(21) |
4,712 |
11.0 |
$7.0 |
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2013 2nd Qtr |
5,525 |
(28) |
4,654 |
11.6 |
$6.6 |
(Slide 10)
Marcellus Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through June 30, 2013, for the company's horizontal wells drilled in the Marcellus Shale. This graph displays a composite curve showing the results of the company's horizontal wells with less than 9 stages (4 well), 9-12 stages (46 wells), 13-18 stages (59 wells), and greater than 18 stages (20 wells). The production data is compared to 4 Bcf, 8 Bcf, 12 Bcf, and 16 Bcf type curves from the company's reservoir simulation shale gas model.
Additionally, this slide contains a line graph displaying gross operated production in MMcf/d for the Marcellus Shale from September 1, 2010 to June 30, 2013. Gross operated production of approx. 503 MMcf/d as of June 30, 2013.
Notes: Data as of June 30, 2013.
(Slide 11)
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 June 30, 2013 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, greater than 3MMcf/d, greater than 5MMcf/d, and greater than 5MMcf/d from 6/30/12 to 6/30/13.
* SWN holds approx. 914,000 net acres in the Fayetteville Shale play (approx 1,400 sq. miles).
* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.
* SWN discovered the Fayetteville Shale and has first mover advantage – average acreage cost of $313 per acre with a 15% royalty and average working interest of 74%.
* We plan to drill approximately 450-460 operated wells in 2013.
Notes: Rates are AOGC Form 13 and Form 3 test rates.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
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2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
6M13 |
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Days to Drill |
17.5 |
13.6 |
11.7 |
10.9 |
7.9 |
6.7 |
5.9 |
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Lateral Length (in feet) |
2,657 |
3,619 |
4,100 |
4,528 |
4,836 |
4,819 |
5,063 |
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Well Cost ($ in millions) |
$2.9 |
$3.0 |
$2.9 |
$2.8 |
$2.8 |
$2.5 |
$2.3 |
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F&D Cost ($ per Mcfe) |
$2.39 |
$1.44 |
$0.80 |
$1.04 |
$1.11 |
$2.53 |
- |
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Production (in Bcf) |
53.5 |
134.5 |
243.5 |
350.2 |
436.8 |
485.5 |
240.1 |
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Reserves (in Bcf) |
716 |
1,545 |
3,117 |
4,345 |
5,104 |
2,988 |
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2012 Change Over 2007 |
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Days to Drill |
-66% |
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Lateral Length (in feet) |
+91% |
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Well Cost ($ in millions) |
-21% |
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Production (in Bcfe) |
+807% |
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Reserves (in Bcfe) |
+317% |
* Continuous improvement in our Fayetteville Shale operations – completed lateral length has increased 91% over the last five and a half years while total well costs decreased 21%.
* Vertical integration and contiguous acreage position allow us significant economies of scale and operating flexibility.
Note: Finding and development costs exclude revisions and capital investments in our sand facility, drilling rig related and ancillary equipment. Production and Reserves growth rates are through 2012 results.
(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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SWN’s Fayetteville Shale gathering system is one of the largest in the U.S. |
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At June 30, 2013, gathering approximately 2.3 Bcf per day through 1,886 miles of gathering lines and 537,900 horsepower of compression equipment. |
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SWN has total firm transportation for the Fayetteville Shale of 2.0 Bcf per day. |
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2012 EBITDA(1) of $338.8 million; Projected EBITDA of $355-$360 million in 2013. |
Note: Map as of June 30, 2013.
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 35.
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 14)
Brown Dense Exploration Project
This slide displays the location of the Lower Smackover Brown Dense play, located on the border of Arkansas and Louisiana, in comparison to East Texas, Arkoma Basin, and Fayetteville Shale plays. The Lower Smackover Brown Dense map highlights oil and gas fields within the project. The map also displays SWN drilled wells, SWN 2013 Plan, and OBO wells. Included in the Lower Smackover Brown Dense map is the location of SWN’s first well Roberson (TA’d) Peak of 103 bc and 180 Mcf, second well Garret (Shut-in) Peak of 301 bc of 1,720 Mcf, third well BML peak of 421 bc and 3,900 Mcf, fouth well Johnson-Vert (shut in after flowback) fifth well Dean- vertical testing peak of 214 bc and 1,207 Mcf, sixth well Doles peak of 435 bc and 2,500 Mcf, seventh well Dean-Hzl is being completed, and the eighth well Sharp-Vert is being completed.
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* SWN currently holds 507,000 net acres in Lower Smackover Brown Dense play. Total land cost of approx. $419 per acre; 81% NRI; leases have 4-year terms and 4-year extensions. |
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* Targeting oil and wet gas window in Upper Jurassic age, kerogen-rich carbonate in southern Arkansas and northern Louisiana. |
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* Targeting 300 to 550 feet thick section at depths of 8,000 - 11,000 feet. |
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* Three wells placed on production. |
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* Completing two wells in the third quarter of 2013. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 15)
Denver Julesburg Basin Exploration Project
This slide displays the location of the Denver Julesburg Basin Exploration Project, located on the border of Colorado, Wyoming, Nebraska, and Kansas. The location of the Las Animas Arch, Ewertz Farm 1-58 #1-26H well (Shut-in), and Staner 5-58 #1-#8 well (Flowing back) is denoted.
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* SWN holds 302,000 net acres at 12/31/12 with a total land cost of approx. $172 per acre; 85% NRI; leases with 5-year terms and 3-year extensions |
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* Targeting unconventional oil in late Pennsylvanian-age carbonates and shales with thicknesses of 300 - 750 feet at depths of 8,000 - 10,500 feet |
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* Recently completed lateral in the Staner 5-58 #1-8 in the Marmaton formation. Well is currently flowing back. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 16)
Outlook for 2013
* Production target of 643-651 Bcfe in 2013 (estimated growth of ~15%).
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2012 |
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2013 Guidance |
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Actual |
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NYMEX Price Assumption |
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$2.79 Gas |
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$3.50 Gas |
$3.75 Gas |
$4.00 Gas |
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$94.94 Oil |
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$85.00 Oil |
$85.00 Oil |
$85.00 Oil |
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Adj. Net Income |
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$485.2 MM(1) |
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$595-$605 MM |
$635-$645 MM |
$680-$690 MM |
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Adj. Diluted EPS |
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$1.39(1) |
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$1.70-$1.73 |
$1.83-$1.86 |
$1.95-$1.98 |
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EBITDA(2) |
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$1,638.3 MM |
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$1,890-$1,900 MM |
$1,960-$1,970 MM |
$2,030-$2,040 MM |
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Net Cash Flow (2) |
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$1,598.9 MM |
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$1,790-$1,800 MM |
$1,860-$1,870 MM |
$1,930-$1,940 MM |
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CapEx |
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$2,080.5 MM |
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$2,250 MM |
$2,250 MM |
$2,250 MM |
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Debt % |
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35% |
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35%-37% |
34%-36% |
33%-35% |
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(1) |
Adjusted net income, adjusted diluted EPS and EBITDA exclude non-cash ceiling test impairments and unrealized gains and losses on derivative contracts. All are non-GAAP financial measures. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 17)
The Road to V+
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* Invest in the Highest PVI Projects. |
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* Flexibility in 2013 Capital Program. |
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* Maintain Strong Balance Sheet. |
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* Deliver the Numbers. |
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* Production and Reserves. |
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* Maximize Cash Flow. |
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* Curiosity to Learning to Innovation to V+. |
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Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 19)
Financial & Operational Summary
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Six Months Ended June 30, |
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Year Ended December 31, |
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2013 |
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2012 |
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2012 |
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2011 |
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2010 |
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($ in millions, except per share amounts) |
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($ in millions, except per share amounts) |
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Revenues |
$ 1,595.7
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$ 1,260.9
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$ 2,715.0
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$ 2,952.9
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$ 2,610.7
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EBITDA (1) |
944.5 | (2) | 736.0 |
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1,638.3 |
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1,775.2 |
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1,612.3 |
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Adjusted Net Income (2) |
335.6 |
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197.7 |
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485.2 |
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637.8 |
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604.1 |
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Net Cash Flow (3) |
918.9 |
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725.3 |
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1,598.9 |
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1,766.0 |
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1,579.7 |
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Adjusted Diluted EPS (2) |
$ 0.96
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$ 0.57
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$ 1.39
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$ 1.82
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$ 1.73
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Diluted CFPS (3) |
$ 2.62
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$ 2.08
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$ 4.59
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$ 5.05
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$ 4.52
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|
|
|
|
|
|
|
|
|
Production (Bcfe) |
307.9 |
|
270.8 |
|
|
565.0 |
|
500.0 |
|
404.7 |
|
|
Realized Avg. Gas Price ($/Mcf) |
$ 3.65
|
|
$ 3.29
|
|
|
$ 3.44
|
|
$ 4.19
|
|
$ 4.64
|
|
|
Realized Avg. Oil Price ($/Bbl) |
$ 104.11
|
|
$ 104.41
|
|
|
$ 101.54
|
|
$ 94.08
|
|
$ 76.84
|
|
|
Realized Avg. NGL Price ($/Bbl) |
$ 45.04
|
|
--- |
|
|
--- |
|
--- |
|
--- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Finding Cost ($/Mcfe) (4) |
|
|
|
|
|
$ 2.08
|
|
$ 1.31
|
|
$ 1.02
|
|
|
Reserve Replacement (%) (4) |
|
|
|
|
|
163% |
|
299% |
|
430% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Debt/Proved Reserves ($/Mcfe) |
|
|
|
|
|
$ 0.42
|
|
$ 0.23
|
|
$ 0.22
|
|
|
Net Debt/Avg. Daily Production ($/Mcfe) |
$ 1,101
|
|
$ 997
|
|
|
$ 1,082
|
|
$ 969
|
|
$ 972
|
|
|
Net Debt/Total Capitalization |
36% |
|
30% |
|
|
35% |
|
25% |
|
27% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 35.
(2) Adjusted net income and adjusted diluted EPS excludes non-cash ceiling test impairments and unrealized gains and losses on derivative contracts. Both are non-GAAP financial measures.
(3) Net cash flow is net cash flow before changes in operating assets and liabilities. Net cash flow and diluted CFPS are non-GAAP financial measures.
(4) Excludes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(Slide 20)
Gas Hedges in Place Through 2014
This slide contains a bar chart detailing gas hedges in place by quarter for year 2013 and year 2014. A summary of these gas hedges is as follows:
|
|
|
|
Average Price per Mcf |
Percent |
|
|
Type |
Hedged Volumes |
(or Floor/Ceiling) |
Hedged |
|
2013 |
Swaps |
285.7 Bcf |
$4.76 |
45% |
|
2014 |
Swaps |
232.7 Bcf |
$4.41 |
- |
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) |
|
Cabot Oil & Gas |
|
$0.75 |
|
Range Resources |
|
$0.76 |
|
Ultra Petroleum |
|
$0.81 |
|
Southwestern Energy Company |
|
$0.93 |
|
Noble Energy |
|
$1.02 |
|
Chesapeake Energy |
|
$1.04 |
|
Forest Oil |
|
$1.10 |
|
SM Energy |
|
$1.26 |
|
EOG Resources |
|
$1.34 |
|
Anadarko Petroleum |
|
$1.44 |
|
Devon Energy |
|
$1.57 |
|
Cimarex Energy |
|
$1.67 |
|
Pioneer Natural Resources |
|
$1.93 |
|
Apache |
|
$2.08 |
|
Newfield Exploration |
|
$2.32 |
|
Sandridge Energy |
|
$2.38 |
|
Murphy |
|
$2.43 |
|
Occidental Petroleum |
|
$2.48 |
|
Marathon |
|
$2.54 |
|
Denbury Resources |
|
$4.15 |
This slide also contains a bar graph comparing SWN to its competitors in terms of Finding & Development Cost per Mcfe (3 year average).
|
|
Finding & Development Cost |
|
|
|
|
per Mcfe |
|
|
|
(3 year average) |
|
Range Resources |
|
$0.95 |
|
Ultra Petroleum |
|
$1.09 |
|
Cabot Oil & Gas |
|
$1.17 |
|
Southwestern Energy Company |
|
$1.48 |
|
Noble Energy |
|
$2.17 |
|
Chesapeake Energy |
|
$2.18 |
|
Anadarko Petroleum |
|
$2.26 |
|
SM Energy |
|
$2.27 |
|
Pioneer Natural Resources |
|
$2.33 |
|
Cimarex Energy |
|
$2.45 |
|
Sandridge Energy |
|
$2.51 |
|
Denbury Resources |
|
$2.56 |
|
EOG Resources |
|
$2.67 |
|
Forest Oil |
|
$2.70 |
|
Devon Energy |
|
$2.90 |
|
Newfield Exploration |
|
$3.09 |
|
Occidental Petroleum |
|
$3.39 |
|
Apache |
|
$4.09 |
|
Murphy |
|
$4.93 |
|
Marathon |
|
$5.13 |
Source: Public filings
Note: All data as of December 31, 2010, 2011 and 2012. APC - Anadarko Petroleum, APA - Apache, COG - Cabot Oil & Gas, CHK - Chesapeake Energy, XEC - Cimarex Energy, DNR - Denbury Resources, DVN - Devon Energy, EOG - EOG Resources, FST - Forest Oil, MRO - Marathon Oil, MUR - Murphy Oil, NFX - Newfield Exploration, NBL - Noble Energy, OXY - Occidental Petroleum, PXD - Pioneer Natural Resources, RRC - Range Resources, SD - Sandridge Energy, SM - SM Energy, SWN - Southwestern Energy, UPL - Ultra Petroleum.
Lifting Cost per Mcfe defined as lease operating expenses plus production taxes divided by production.
F&D Cost per Mcfe defined as the three-year sum of costs incurred in natural gas and oil exploration and development divided by the three-year sum of reserve additions from extensions and discoveries, improved recovery, revisions and purchases (excludes revisions).
(Slide 22)
Fayetteville Shale - Horizontal Well Performance
|
Time Frame |
Wells Placed on Production |
Average IP Rate (Mcf/d) |
30th-Day Avg Rate (# of wells) |
60th-Day Avg Rate (# of wells) |
Avg Lateral Length |
||||
|
1st Qtr 2007 |
|
58 |
1,261 |
|
1,066 |
(58) |
958 |
(58) |
2,104 |
|
2nd Qtr 2007 |
|
46 |
1,497 |
|
1,254 |
(46) |
1,034 |
(46) |
2,512 |
|
3rd Qtr 2007 |
|
74 |
1,769 |
|
1,510 |
(72) |
1,334 |
(72) |
2,622 |
|
4th Qtr 2007 |
|
77 |
2,027 |
|
1,690 |
(77) |
1,481 |
(77) |
3,193 |
|
1st Qtr 2008 |
|
75 |
2,343 |
|
2,147 |
(75) |
1,943 |
(74) |
3,301 |
|
2nd Qtr 2008 |
|
83 |
2,541 |
|
2,155 |
(83) |
1,886 |
(83) |
3,562 |
|
3rd Qtr 2008 |
|
97 |
2,882 |
|
2,560 |
(97) |
2,349 |
(97) |
3,736 |
|
4th Qtr 2008 |
(1) |
74 |
3,350 |
(1) |
2,722 |
(74) |
2,386 |
(74) |
3,850 |
|
1st Qtr 2009 |
(1) |
120 |
2,992 |
(1) |
2,537 |
(120) |
2,293 |
(120) |
3,874 |
|
2nd Qtr 2009 |
|
111 |
3,611 |
|
2,833 |
(111) |
2,556 |
(111) |
4,123 |
|
3rd Qtr 2009 |
|
93 |
3,604 |
|
2,624 |
(93) |
2,255 |
(93) |
4,100 |
|
4th Qtr 2009 |
|
122 |
3,727 |
|
2,674 |
(122) |
2,360 |
(120) |
4,303 |
|
1st Qtr 2010 |
(2) |
106 |
3,197 |
(2) |
2,388 |
(106) |
2,123 |
(106) |
4,348 |
|
2nd Qtr 2010 |
|
143 |
3,449 |
|
2,554 |
(143) |
2,321 |
(142) |
4,532 |
|
3rd Qtr 2010 |
|
145 |
3,281 |
|
2,448 |
(145) |
2,202 |
(144) |
4,503 |
|
4th Qtr 2010 |
|
159 |
3,472 |
|
2,678 |
(159) |
2,294 |
(159) |
4,667 |
|
1st Qtr 2011 |
|
137 |
3,231 |
|
2,604 |
(137) |
2,238 |
(137) |
4,985 |
|
2nd Qtr 2011 |
|
149 |
3,014 |
|
2,328 |
(149) |
1,991 |
(149) |
4,839 |
|
3rd Qtr 2011 |
|
132 |
3,443 |
|
2,666 |
(132) |
2,372 |
(132) |
4,847 |
|
4th Qtr 2011 |
|
142 |
3,646 |
|
2,606 |
(142) |
2,243 |
(142) |
4,703 |
|
1st Qtr 2012 |
|
146 |
3,319 |
|
2,421 |
(146) |
2,131 |
(146) |
4,743 |
|
2nd Qtr 2012 |
|
131 |
3,500 |
|
2,515 |
(131) |
2,225 |
(131) |
4,840 |
|
3rd Qtr 2012 |
|
105 |
3,857 |
|
2,816 |
(105) |
2,447 |
(105) |
4,974 |
|
4th Qtr 2012 |
|
111 |
3,962 |
|
2,815 |
(111) |
2,405 |
(111) |
4,784 |
|
1st Qtr 2013 |
|
102 |
3,301 |
|
2,373 |
(76) |
2,133 |
(45) |
4,942 |
|
2nd Qtr 2013 |
|
126 |
3,625 |
|
2,245 |
(102) |
1,972 |
(68) |
5,165 |
Note: Data as of June 30, 2013.
Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to January 2013. Gross operated production of approx. 2,027 MMcf/d as of June 30, 2013. Periods of production affected by pipeline curtailment issues are denoted.
* Gross operated production of approx. 2,027 MMcf/d as of June 30, 2013
* 2012 Fayetteville Shale F&D cost of $2.53/Mcf
(Slide 21)
Marcellus Shale – Horizontal Well Performance
|
|
30th-Day Avg. Rate (# of Wells) |
60th-Day Avg. Rate (# of Wells) |
120th-Day Avg. Rate (# of Wells) |
Average of CLAT (ft) |
|||
|
Q3 2010 |
1,405 |
(1) |
3,680 |
(1) |
2,491 |
(1) |
2,927 |
|
Q4 2010 |
5,584 |
(6) |
5,602 |
(6) |
5,446 |
(6) |
3,805 |
|
Q1 2011 |
5,052 |
(3) |
6,013 |
(3) |
5,525 |
(3) |
3,864 |
|
Q2 2011 |
6,114 |
(7) |
6,835 |
(7) |
8,231 |
(7) |
4,780 |
|
Q4 2011 |
5,284 |
(5) |
4,508 |
(5) |
6,011 |
(5) |
4,129 |
|
Q1 2012 |
7,327 |
(2) |
8,247 |
(2) |
7,966 |
(2) |
4,009 |
|
Q2 2012 |
3,859 |
(17) |
3,677 |
(17) |
3,958 |
(17) |
3,934 |
|
Q3 2012 |
4,493 |
(8) |
4,654 |
(8) |
4,682 |
(8) |
4,380 |
|
Q4 2012 |
4,606 |
(22) |
4,760 |
(22) |
5,151 |
(12) |
3,830 |
|
Q1 2013 |
4,923 |
(12) |
5,438 |
(2) |
|
|
3,976 |
Notes: Data as of June 30, 2013.
Fayetteville Shale - Horizontal Well Performance
The graph contained in this slide provides average daily production data through December 31, 2012, for the company's horizontal wells drilled in the Fayetteville Shale. This graph displays four composite curves, one composite curve showing the SW/XL normalized production from all the company's horizontal wells and three composite curves showing the results of the company's horizontal wells with laterals greater than 3,000 feet, greater than 4,000 feet, and greater than 5,000 feet. The production data is compared to 2 Bcf, 3 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model. Well counts and respective days of production are also displayed, as follows:
|
Days of Production |
Total Well Count |
Horizontal Wells with Laterals > 3,000 Feet |
Horizontal Wells with Laterals > 4,000 Feet |
Horizontal Wells with Laterals > 5,000 Feet |
| 0 | 2,921 | 2,418 | 1,574 | 613 |
| 100 | 2,822 | 2,396 | 1,572 | 616 |
| 200 | 2,696 | 2,252 | 1,451 | 568 |
| 300 | 2,582 | 2,155 | 1,370 | 529 |
| 400 | 2,477 | 2,029 | 1,290 | 479 |
| 500 | 2,315 | 1,872 | 1,158 | 417 |
| 600 | 2,150 | 1,704 | 1,020 | 341 |
| 700 | 2,008 | 1,577 | 923 | 300 |
| 800 | 1,862 | 1,434 | 803 | 246 |
| 900 | 1,685 | 1,271 | 664 | 183 |
| 1,000 | 1,537 | 1,132 | 557 | 146 |
| 1,100 | 1,381 | 960 | 435 | 94 |
| 1,200 | 1,226 | 842 | 343 | 60 |
| 1,300 | 1,089 | 719 | 275 | 37 |
| 1,400 | 966 | 625 | 206 | 23 |
| 1,500 | 863 | 532 | 163 | 13 |
Note: Data as of June 30, 2013. Excludes wells with mechanical problems (31).
Drilling & Completion Major Cost Categories
Average 2012 Fayetteville Shale Well Cost Estimate
This slide displays the estimated average 2013 major well cost categories as a proportion to the total average well costs.
|
|
Average 2013 Fayetteville Shale Well Cost Estimate |
|
|
(in thousands) |
|
Fracture Stimulation |
$ 651
|
|
Rig |
243.5 |
|
OCTG |
218 |
|
Environmental & Restoration |
143 |
|
Drilling Fluids |
136 |
|
Directional Drilling |
94 |
|
Wellhead & Surface Equipment |
101 |
|
Other |
33 |
|
Water Treatment/Disposal |
246 |
|
Supervision |
76 |
|
Surface Rentals |
75 |
|
Location |
64 |
|
Wireline |
87 |
|
Rentals |
22 |
|
Coil Tubing |
84 |
|
D&C Fluids |
64 |
|
Bits |
40 |
|
Cementing |
38 |
|
Fuel & Water |
55 |
|
Trucking & Transportation |
9 |
|
Formation Evaluation |
46 |
|
Special Services |
25 |
|
Land & Damages |
34 |
|
Major Cost Categories |
$ 2,585
|
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(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)
25% Recycle/Reused Water SGW, FBW, & PW
75% Surface Water
A box accompanying the graphs states:
SWN Operations Less than 0.09% of State’s water demand
Source: U.S. Geological Survey, Central Arkansas Water, Southwestern Energy Company estimates.
Shallow Ground Water (SGW) – Ground water recovered from shallow formations during the air drilling process.
Flow Back Water (FBW) – Frac Fluid that is recovered from the well after the fracture stimulation.
Produced Water (PW) – Natural formation water that is returned to the surface throughout the producing life of the well.
(Slide 26)
Ark-La-Tex Division
This slide contains a map of the ArkLaTex Division, which is composed of East Texas and Arkoma Basin, in relation to Texas, Oklahoma, Arkansas, and Louisiana. The slide also contains two graphs outlining the production, capital expenditures, and reserves for East Texas (sold Overton field in 2012) and Arkoma Basin for the period extending from 2000 to 2012, summarized as follows:
|
|
Arkoma Basin |
||||||||||||
|
|
2000 |
2001 |
2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
|
Production (Bcfe) |
19.9 |
22.3 |
19.8 |
18.9 |
20.1 |
20.2 |
20.1 |
23.8 |
24.4 |
22 |
19.2 |
16.3 |
14.1 |
|
Reserve (Bcfe) |
200.3 |
186 |
188.7 |
211.7 |
239.5 |
271 |
277 |
304 |
281 |
208 |
226 |
194 |
160 |
|
Capex (in millions) |
$ 17.6
|
$ 28.6
|
$ 18.2
|
$ 32.9
|
$ 53.2
|
$ 64.5
|
$ 97.0
|
$ 148.0
|
$ 133.0
|
$ 40.0
|
$ 13.0
|
$ 7.7
|
6.0 |
|
|
East Texas |
|||||||||||||||
|
|
2000 |
2001 |
2002 |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
2010 |
2011 |
2012 |
|||
|
Production (Bcfe) |
0.3 |
2.3 |
5.9 |
13.6 |
22.2 |
28.2 |
32 |
29.9 |
31.6 |
34.9 |
34.3 |
23.5 |
11.4 |
|||
|
Reserve (Bcfe) |
22 |
57.6 |
111 |
196.3 |
299.1 |
368.7 |
383 |
353 |
351 |
330 |
321 |
253 |
53 |
|||
|
Capex (in millions) |
$ 6.1
|
$ 30.9
|
$ 33.6
|
$ 97.3
|
$ 156.7
|
$ 183.6
|
$ 204.0
|
$ 201.0
|
$ 160.0
|
$ 167.0
|
$ 150.0
|
$ 68.0
|
$5.0 |
|||
Arkoma Basin
Acreage: 114,287 net acres (at 12/31/12)
2012 Reserves: 160 Bcf (4% of total)
2012 Production: 14.1 Bcf (2% of total)
East Texas
Acreage: 49,340 net acres (at 12/31/12)
2012 Reserves: 53 Bcfe (1% of total)
2012 Production: 11.4 Bcfe (2% of total)
Notes: Conventional Arkoma acreage excludes 124,653 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area.
(Slide 27)
New Brunswick, Canada Exploration Project
This slide contains a map of the Province of New Brunswick, Canada. The acreage on which the company has obtained licenses to explore is highlighted on the map: Marysville (2,309,247 acres) and Cocagne (209,271 acres). The McCully Field, Stoney Creek Field, M&NE Pipeline and the Green Road G-41 well are denoted on the map.
|
* SWN currently holds exploration licenses to over 2.5 million acres within the Maritimes Basin |
|
|
* Principal targets are the conventional and unconventional sandstone and shale reservoirs of the Horton Group (Frederick Brook Shale) |
|
|
* Oil and gas production from fields along southern flank: |
|
|
|
* McCully - reserves 190 bcfg |
|
|
* Stoney Creek - cum 800,000 bo, 30 bcfg |
|
* 3-year initial exploration license to complete work program |
|
|
|
* $47MM total work commitment with options for multiple 5-year extension leases |
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 29)
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 30)
U.S. Electricity Generation
This slide contains a chart showing Electricity Generation by Energy Source as a percentage of total.
Total 4,100 Billion kWh in 2011.
|
% of Total Electricity Generation |
|
|
Coal |
42% |
|
Natural Gas |
25% |
|
Nuclear |
19% |
|
Hydroelectric |
8% |
|
Wind |
3% |
|
Other Renewables (1) |
2% |
|
Other (2) |
1% |
Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2010 compared to Trailing 12 Months Generation.
While coal and nuclear power plants operate at very high capacity, natural gas power plants are only running at 33% of their capacity.
|
Electricity Generation Capacities |
Trailing 12 Month Generation (3) |
2010 Capacity |
Unused Capacity |
|
Nuclear |
90,326 |
101,167 |
11% |
|
Coal |
178,459 |
316,800 |
44% |
|
Natural Gas |
133,325 |
407,028 |
67% |
|
1. |
Geothermal, solar, wood and waste |
|
2. |
Petroleum and others gases |
|
3. |
July 2011 – June 2012 |
Source: EIA
(Slide 31)
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 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 1997 to present.
Source: Bloomberg
(Slide 33)
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, |
|||
|
|
|
2013 |
|
2012 |
|
|
|
|
(in thousands) |
|||
|
Net cash provided by operating activities |
|
$ 877,552
|
|
$ 837,390
|
|
|
Add back (deduct): |
|
|
|
|
|
|
Change in operating assets and liabilities |
|
41,337 |
|
(112,043) |
|
|
Net cash flow |
|
$ 918,889
|
|
$ 725,347
|
|
|
|
|
12 Months Ended December 31, |
||||
|
|
|
2012 |
|
2011 |
|
2010 |
|
|
|
(in thousands) |
||||
|
Net cash provided by operating activities |
|
$ 1,653,942
|
|
$ 1,739,817
|
|
$ 1,642,585
|
|
Add back (deduct): |
|
|
|
|
|
|
|
Change in operating assets and liabilities |
|
(55,061) |
|
26,201 |
|
(62,906) |
|
Net cash flow |
|
$ 1,598,881
|
|
$ 1,766,018
|
|
$ 1,579,679
|
|
|
|
2013 Guidance |
|||
|
|
|
NYMEX Commodity Price Assumption |
|||
|
|
|
$3.50 Gas |
|
$3.75 Gas |
$4.00 Gas |
|
|
|
$85.00 Oil |
|
$85.00 Oil |
$85.00 Oil |
|
|
|
($ in millions) |
|||
|
Net cash provided by operating activities |
|
$1,790 - $1,810 |
|
$1,860 - $1,870 |
$1,930 - $1,940 |
|
Add back (deduct): |
|
|
|
|
|
|
Assumed change in operating assets and liabilities |
|
-- |
|
-- |
-- |
|
Net cash flow |
|
$1,790 - $1,800 |
|
$1,860 - $1,870 |
$1,930 - $1,940 |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".
(Slide 34)
Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income
Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.
|
|
6 Months Ended |
|
6 Months Ended |
||||
|
|
June 30, 2013 |
|
June 30, 2012 |
||||
|
|
($ in thousands) |
|
(per share) |
|
($ in thousands) |
|
(per share) |
|
Net income attributable to SWN |
$ 373,146
|
|
$ 1.06
|
|
$ (297,428)
|
|
$ (0.85)
|
|
Add back (deduct): |
|
|
|
|
|
|
|
|
Impairment of natural gas & oil properties (net of taxes) |
--- |
|
--- |
|
496,370 |
|
1.43 |
|
Unrealized gain (loss) on derivative contracts (net of taxes) |
(37,503) |
|
$ (0.10)
|
|
(1,259) |
|
(0.01) |
|
Adjusted net income |
$ 335,643
|
|
$ 0.96
|
|
$ 197,683
|
|
$ 0.57
|
|
|
12 Months Ended |
|
12 Months Ended |
||||
|
|
December 31, 2012 |
|
December 31, 2009 |
||||
|
|
($ in thousands) |
|
(per share) |
|
($ in thousands) |
|
(per share) |
|
Net loss attributable to SWN |
$ (707,064)
|
|
$ (2.03)
|
|
$ (35,650)
|
|
$ (0.10)
|
|
Add back (deduct): |
|
|
|
|
|
|
|
|
Impairment of natural gas & oil properties (net of taxes) |
1,192,412 |
|
3.42 |
|
558,305 |
|
1.62 |
|
Unrealized gain (loss) on derivative contracts (net of taxes) |
(167) |
|
--- |
|
--- |
|
--- |
|
Adjusted net income |
$ 485,181
|
|
$ 1.39
|
|
$ 522,655
|
|
$ 1.52
|
(Slide 35)
Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA
|
6 Months Ended June 30, |
|||
|
|
2013 |
|
2012 |
|
|
|
|
|
|
Net income (loss) attributable to SWN |
$ 373,146
|
|
$ (297,429)
|
|
Add back (deduct): |
|
|
|
|
Net interest expense |
18,299 |
|
15,699 |
|
Provision (benefit) for income taxes |
249,308 |
|
(182,328) |
|
Depreciation, depletion and amortization |
366,334 |
|
1,202,109 |
|
Less: Unrealized gains (losses) on derivatives (1) |
62,559 |
|
2,031 |
|
EBITDA |
$ 944,528
|
|
$ 736,020
|
|
|
12 Months Ended December 31, |
|||||||||||||||||||||
|
|
2012 |
|
2011 |
|
2010 |
|
2009 |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
|
|
($ in thousands) |
|||||||||||||||||||||
|
Net income (loss) |
$(707,064) |
(5) |
$ 637,769 |
|
$ 604,118 |
|
$ (35,650) |
(4) |
$567,946 |
|
$221,174 |
|
$162,636 |
|
$147,760 |
|
$103,576 |
|
$48,897 |
|
$14,311 |
|
|
Add back: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
35,657 |
|
24,075 |
|
26,163 |
|
18,638 |
|
28,904 |
|
23,873 |
|
679 |
|
15,040 |
|
16,992 |
|
17,311 |
|
21,466 |
|
|
Provision (benefit) for income taxes |
(443,139) |
(6) |
413,221 |
|
391,659 |
|
(16,363) |
(9) |
350,999 |
|
135,855 |
|
99,399 |
|
86,431 |
|
59,778 |
|
28,372 |
(11) |
8,708 |
|
|
Depreciation, depletion and amortization |
2,750,687 |
(7) |
704,511 |
|
590,332 |
|
1,401,470 |
(10) |
414,460 |
|
294,500 |
|
151,795 |
|
96,641 |
|
74,919 |
|
56,833 |
|
54,095 |
|
|
Less: Unrealized gains (losses) on derivatives (1) |
(2,154) |
|
4,423 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDA |
$1,638,295 |
|
$1,775,153 |
|
$1,612,272 |
|
$1,368,095 |
|
$1,362,309 |
|
$675,402 |
|
$414,509 |
|
$345,872 |
|
$255,265 |
|
$151,413 |
|
$98,580 |
|
|
(1) Unrealized gains (losses) were excluded from the EBITDA calculation for the year 2011 and thereafter. |
|
(2) Net income (loss) includes after tax full cost ceiling impairments of our natural gas and oil properties of $496.4 million. |
|
(3) Provision (benefit) for income taxes includes the ($304.3) million income tax benefit related to the non-cash ceiling impairments of our natural gas and oil properties. |
|
(4) Depreciation, depletion and amortization includes $800.7 million for non-cash ceiling impairments of our natural gas and oil properties. |
|
(5) Net income (loss) includes after tax full cost ceiling impairments of our natural gas and oil properties of $1,192.4 million. |
|
(6) Provision (benefit) for income taxes includes the ($747.3) million income tax benefit related to the non-cash ceiling impairments of our natural gas and oil properties. |
|
(7) Depreciation, depletion and amortization includes $1,939.7 million for non-cash ceiling impairments of our natural gas and oil properties. |
|
(8) 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. |
|
(9) 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. |
|
(10) Depreciation, depletion and amortization includes the $907.8 million non-cash ceiling impairment of our natural gas and oil properties recorded in Q1 2009. |
|
(11) 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 2013, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2013, including current hedges in place:
|
|
|
2013 Guidance |
|||||||||
|
|
|
Overall Corporate |
|
|
|||||||
|
|
|
NYMEX Commodity Price Assumption |
|
|
|||||||
|
|
|
$3.50 Gas |
|
$3.75 Gas |
|
$4.00 Gas |
|
Midstream Services Segment(1) |
|||
|
|
|
$85.00 Oil |
|
$85.00 Oil |
$85.00 Oil |
|
|||||
|
|
|
($ in millions) |
|||||||||
|
Net income attributable to SWN |
|
$595-$605 |
|
$635-$645 |
|
$680-$690 |
|
$170-$175 |
|||
|
Add back: |
|
|
|
|
|
|
|
|
|||
|
Provision for income taxes |
|
397-403 |
|
423-430 |
|
453-460 |
|
113-117 |
|||
|
Interest expense |
|
36-38 |
|
35-37 |
|
34-36 |
|
13-15 |
|||
|
Depreciation, depletion and amortization |
|
850-860 |
|
850-860 |
|
850-860 |
|
55-57 |
|||
|
EBITDA |
|
$1,890-$1,900 |
|
$1,960-$1,970 |
|
$2,030-$2,040 |
|
$355-$360 |
|||
|
(1) |
Midstream Services segment results assume NYMEX commodity prices of $3.50 per Mcf for natural gas and $85.00 per barrel for crude oil for 2013. |
Note that the information contained on this slide constitutes a "Forward-Looking Statement".