EX-99 2 exhibit991.htm SWN FEBRUARY 2013 INVESTOR PRESENTATION SWN Investor Presentation February 2013

 

EXHIBIT 99.1

Slide Presentation dated February 2013

(Cover)
Southwestern Energy

February 2013 Update

 

NYSE: SWN

The left side of this slide contains a photograph of a pulley system. Each new line added to a pulley reduces the force needed to successfully lift an object. The basic block and tackle is our formula.

 

(Slide 1)
Southwestern Energy Company

General Information

Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in natural gas and oil exploration and production and natural gas gathering and marketing.

Market Data as of February 22, 2013

 

 

NYSE: SWN

 

Shares of Common Stock Outstanding

351,097,392

Market Capitalization

$12,017,000,000

Institutional Ownership

93.1%

Management and Board Ownership

2.8%

52-Week Price Range

$25.82  (6/13/12) - $36.60 (11/23/12)

 

Investor Contacts

Steve Mueller
President and Chief Executive Officer

Phone:

(281) 618-4800

Fax:

(281) 618-4820

 

Brad D. Sylvester, CFA
Vice President, Investor Relations

Phone:

(281) 618-4897

Fax:

(281) 618-4820

 

 

 

 

(Slide 2)
Forward-Looking Statements

All statements, other than historical facts and financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company’s ability to fund the company’s planned capital investments; the company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play overall as well as relative to other productive shale gas plays; the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives; the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s future property acquisition or divestiture activities; the impact of the adverse outcome of any material litigation against the company; the effects of weather; increased competition and regulation; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

The SEC has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.

The contents of this presentation are current as of February 22, 2013.

 

 

 

(Slide 3)
About Southwestern 

 

 

* Focused on exploration and production of natural gas.

 

* 4.0 Tcfe of reserves; 7.1 R/P at year-end 2012.

 

* E&P strategy built on organic growth through the drillbit.

 

* Approximately 75% of planned E&P capital allocated to drilling in 2013.

 

* Track record of adding significant reserves at low costs.

 

* From 2007 to 2012, we’ve averaged over 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).

 

 

 

* Strategy built on the Formula:

 

The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+.

 

(1)

Reserve replacement ratio and finding and development costs exclude reserve revisions and capital investments 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)
2012 Highlights and 2013 Outlook

 

 

 

* Full-year 2012 Highlights

 

 

*  Production of 565 Bcfe, up 13%, due to strong Fayetteville and Marcellus results.

 

*  Recorded 2nd highest cash flow in company history despite low gas prices, primarily driven by low cash operating costs (1) and the continued strong growth from our Midstream business.

 

*  Currently drilling on 3 New Ventures ideas – the Lower Smackover Brown Dense formation in southern Arkansas and northern Louisiana, the Marmaton/Atoka oil play in Colorado and the Bakken/Three Forks play in Montana

 

*  Strong balance sheet and financial position as of December 31, 2012:

 

 

*  Debt-to-book capitalization ratio of 35%

 

 

*  $1.5 billion revolving credit facility undrawn at year-end

 

 

*  Cash and restricted cash on hand of approximately $62 million

 

 

 

 

* Strong Growth and Low-Cost Operations Set the Stage for a Record 2013

 

 

*  2013 projected capital investment program of $2.0 billion.

 

*  2013 production projected to grow 12%.

 

 

 

 

 

 

 

 

(1)

Cash operating costs for the twelve months ended December 31, 2012 include lease operating expenses ($0.80/Mcfe), general and administrative expenses ($0.26/Mcfe), taxes other than income taxes ($0.10/Mcfe) and net interest expense ($0.04/Mcfe).

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

 

(Slide 5)
Proven Track Record

This slide contains bar charts for the periods ended December 31.

 

 

 

 

 

 

 

 

 

 

 

 

 

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Production (Bcfe)

40

41

54

61

72

113

195

300

405

500

565

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

Proved Reserves (Bcfe)

415

503

646

827

1,026

1,450

2,185

3,657

4,937

5,893

4,018

EBITDA ($MM)(1)
$
99 
$
151 
$
255 
$
346 
$
415 
$
675 
$
1,362 
$
1,368 
$
1,612 

$ 1,780 

1,636

F&D Cost ($/Mcfe)
$
1.01 
$
1.18 
$
1.34 
$
1.51 
$
2.08 
$
2.70 
$
1.70 
$
0.91 
$
1.24 

$    1.34

2.08

 

Note: Reserve data excludes reserve revisions and capital investments in our sand facility, drilling rig related and ancillary equipment.

      

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 34.

 

 

 (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

 

 

* 2012:

4,018 Bcfe of Reserves

 

Production – 565.0 Bcfe

* 2013  

Est. Production: 628-640 Bcfe

 

 

New Ventures

 

* Brown Dense – Approx. 507,000 net acres

* Colorado – Approx. 302,000 net acres

* New Brunswick – Approx. 2.5 million acres

* Undisclosed Ventures – Approx. 495,000 net acres

 

Fayetteville Shale

 

* Reserves: 2,988 Bcf (75%)

* Production: 485.5 Bcf (86%)

* Net Acres: 913,502 (12/31/12)

 

 

Ark-La-Tex

* Reserves: 213 Bcfe (5%)

* Production: 25.6 Bcfe (5%)

* Net Acres: 163,627 (12/31/12)  

 

Marcellus Shale

* Reserves: 816 Bcf (20%)

* Production: 53.6 Bcf (9%)

* Net Acres: 176,298  (12/31/12)

 

 

 Notes:   

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):  

 

 

 

 

 

 

 

 

2013

 

2006

2007

2008

2009

2010

2011

2012

Plan

Corporate & Other
$
32 
$
16 
$
17 
$
30 
$
73 
$
69 
$
55 
$
40 

Midstream Services

 49  107  183  214  271  161  165  160 

Drilling Rigs

 94  5 

- 

- 

- 

- 

- 

- 

Property Acquisitions

 18  2 

- 

- 

 1 

- 

- 

- 

Cap. Expense & Other E&P

 62  77  153  190  185  220  269  318 

Leasehold & Seismic

 70  166  149  114  215  257  196  123 

Development Drilling

 421  1,110  1,255  1,257  1,370  1,486  1,257  1,274 

Exploration Drilling

 196  20  39  4  5  14  139  70 

Total
$
942 
$
1,503 
$
1,796 
$
1,809 
$
2,120 
$
2,207 
$
2,081 
$
1,985 

Additionally, this slide contains a pie chart of the company's planned 2012 capital investments by area of operation, summarized as follows:

 

 

 

% of Total

 

Capital Investments

Fayetteville Shale

42%

Marcellus

35%

Midstream

8%

New Ventures

12%

Corp/Other

2%

Other Areas

1%  

 

 

 

 

*  E&P capital program heavily weighted to low-risk development drilling in 2013.

 

 

* Plan to invest approximately $900 million in the Fayetteville Shale and $800 million in the Marcellus Shale (including Midstream) in 2013.

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

(Slide 8)
Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale Focus Area in Arkansas.  Well locations for all wells drilled from inception of the play through December 31, 2012 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, greater than 3MMcf/d and greater than 6MMcf/d.

*  SWN holds approx. 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 385-390 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".

 

(Slide 9)
Fayetteville Shale – Continuous Improvement

 

2007

2008

2009

2010

2011

2012

Days to Drill

17

14

12

11

8

6.7

Lateral Length (in feet)

2,657

3,619

4,100

4,528

4,836

4,833

Well Cost ($ in millions)

$2.9

$3.0

$2.9

$2.8

$2.8

$2.5

F&D Cost ($ per Mcf)

$2.05

$1.21

$0.69

$0.86

$1.13

$2.53

Production (in Bcf)

53.5

134.5

243.5

350.2

436.8

485.5

Reserves (in Bcf)

716

1,545

3,117

4,345

5,104

2,988

 

 

 

 

 

2012 Change Over 2007

Days to Drill

-62%

Lateral Length (in feet)

+82%

Well Cost ($ in millions)

-14%

Production (in Bcf)

+807%

Reserves (in Bcf)

+317%

 

*  Continuous improvement in our Fayetteville Shale operations – completed lateral length has increased 82% over the last four years holding total well costs decreased 14%.

 

*  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.

 

(Slide 10)

Midstream - Adding Value Beyond the Wellhead

This slide contains a map of several counties in Arkansas where the company's Fayetteville Shale Focus Area is located.  These counties include Johnson, Pope, Van Buren, Cleburne, Logan, Yell, Conway, Faulkner and White.  Lines trace DeSoto Gathering Lines and the Ozark, Centerpoint, Boardwalk, NGPL, MRT and TETCO transmission pipelines.  Compression facilities are also indicated on the map.

*

SWN’s Fayetteville Shale gathering system is one of the largest in the U.S.

 

 

*

At December 31, 2012, gathering approximately 2.3 Bcf per day through 1,852 miles of gathering lines, up from approximately 2.1 Bcf per day the same time a year ago.

 

 

*

SWN has total firm transportation for the Fayetteville Shale of 2.0 Bcf per day.

 

 

*

2012 EBITDA(1) of $338.8 million;  Projected EBITDA of $355-$360 million in 2013.

 

Note:  Map as of December 31, 2012.

(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 11)

Marcellus Shale

 

This slide contains a map of several counties in Pennsylvania and New York and certain well production data.  The company's acreage positions are highlighted.  The locations of the company's test wells are shown on the map: Greenzweig, Range Trust, Price and Lycoming.  Lines trace the Transco, Tennessee Gas, Millennium, Stagecoach, PVR Line, and Bluestone transmission pipelines. This chart also notes planned wells in 2013 for Lycoming County (11 wells), Bradford County (32 wells), and Susquehanna County (44 wells).

 

 

*

We hold approximately 176,000 net acres in Northeast Pennsylvania.

 

 

*

On December 31, 2012, our gross operated production from the Marcellus Shale was approximately 300 MMcf/d from 71 operated horizontal wells.

 

 

*

We plan to drill up to 86-88 wells in 2013.

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

 

 

(Slide 12)

Marcellus Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 31, 2012, for the company's horizontal wells drilled in the Marcellus Shale.  This graph displays a composite curve showing the results of the company's horizontal wells with less than 9 stages (4 well), 9-12 stages (40 wells), and greater than 12 stages (27 wells).The production data is compared to 10 Bcf, 8 Bcf, 6 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model. 

Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Marcellus Shale from September 1, 2010 to December 31, 2012. Gross operated production of approx. 300 MMcf/d as of December 31, 2012.

Notes: Data as of December 31, 2012.  

 

(Slide 13)
Brown Dense Exploration Project

This slide displays the location of the Lower Smackover Brown Dense play, located on the border of Arkansas and Louisiana, in comparison to East Texas, Arkoma Basin, and Fayetteville Shale plays.  The Lower Smackover Brown Dense map highlights oil 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 bo and 180 Mcf,  second well Garret (Shut-in) Peak of 301 bo of 1,720 Mcf, third well BML peak of 421 bo and 3,900 Mcf, fouth well Johnson-Vert (shut in after flowback) fifth well Dean- vertical testing peak of 214 bo and 1,207 Mcf,, and sixth well DolesPeak of 435 bo and 2,500 Mcf.

 

* 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.

* Targeting oil window in Upper Jurassic age, kerogen-rich carbonate in southern Arkansas and northern Louisiana with horizontal drilling.

* Targeting 300 to 550 feet thick section at depths of 8,000 - 11,000 feet.

* Three wells placed on production.

* Finalize tentative agreement with joint venture partner in first quarter 2013.

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

(Slide 14)
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 #1-26 well  (shut-in), and Staner 5-58 #1-8H well (drilling Hz) is denoted.

 

*  SWN held 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.

*  Targeting unconventional oil in late Pennsylvanian-age carbonates and shales with thicknesses of 300 - 750 feet at depths of 8,000 - 10,500 feet.

 

 

*  Currently, drilling a lateral in the Staner 5-58 #1-8H to further test objectives

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

(Slide 15)
Outlook for 2013

*  Production target of 628-640 Bcfe in 2013 (estimated growth of ~12%).

 

 

 

 

 

 

 

 

 

2012

 

2013 Guidance

 

 

Actual 

 

NYMEX Price Assumption

 

 

$2.79 Gas

 

$3.25 Gas

$3.50 Gas

$3.75 Gas

 

 

$94.94 Oil

 

$85.00 Oil

$85.00 Oil

$85.00 Oil

Adj. Net Income

 

$485.2 MM(1)

 

$460-$470 MM

$525-$535 MM

$585-$595 MM

Adj. Diluted EPS

 

$1.39(1)

 

$1.31-$1.34

$1.50-$1.53

$1.67-$1.70

EBITDA(2)

 

$1,636.1 MM

 

$1,680-$1,690 MM

$1,780-$1,790 MM

$1,880-$1,890 MM

Net Cash Flow  (2)

 

$1,598.9 MM

 

$1,650-$1,660 MM

$1,750-$1,760 MM

$1,850-$1,860 MM

CapEx

 

$2,080.5 MM

 

$1,985 MM

$1,985 MM

$1,985 MM

Debt %

 

35%(3)

 

34%-36%

32%-34%

30%-32%

 

(3)    2012 projected book capitalization includes the effect of the $1,192.4 million (after-tax) non-cash ceiling test impairments recorded in 2012.

 

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.

 

 

*  Flexibility in 2013 Capital Program.

 

* Maintain Strong Balance Sheet.

 

* Deliver the Numbers.

 

* Production and Reserves.

 

* Maximize Cash Flow.

 

 

*  Curiosity to Learning to Innovation to V+.

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

(Slide 17)
Appendix

 

(Slide 18)
Financial & Operational Summary

 

 

Year Ended December 31,

 

 

 

2012

 

2011

 

2010

 

 

 

 

 

 

 

 

 

 

 

($ in millions, except per share amounts)

 

Revenues

 
$
2,715.0 

 
$
2,952.9 

 
$
2,610.7 

 

EBITDA (1)

 

 1,636.1 

 

 1,779.6 

 

 1,612.3 

 

Adjusted Net Income

 

 485.2 

(2)

 637.8 

 

 604.1 

 

Net Cash Flow (1)

 

 1,598.9 

 

 1,766.0 

 

 1,579.7 

 

Adjusted Diluted EPS

 
$
1.39 

(2)
$
1.82 

 
$
1.73 

 

Diluted CFPS (1)

 
$
4.59 

 
$
5.05 

 
$
4.52 

 

 

 

 

 

 

 

 

 

Production (Bcfe)

 

 565.0 

 

 500.0 

 

 404.7 

 

Avg. Gas Price ($/Mcf)

 
$
3.44 

 
$
4.19 

 
$
4.64 

 

Avg. Oil Price ($/Bbl)

 
$
101.54 

 
$
94.08 

 
$
76.84 

 

 

 

 

 

 

 

 

 

Finding Cost ($/Mcfe) (3)

 
$
2.08 

 
$
1.34 

 
$
1.24 

 

Reserve Replacement (%) (3)

 

 163% 

 

 292% 

 

 354% 

 

 

 

 

 

 

 

 

 

Net Debt/Proved Reserves ($/Mcfe)

 
$
0.52 

 
$
0.22 

 
$
0.22 

 

Net Debt/Avg. Daily Production ($/Mcfe)

 
$
1,082 

 
$
981 

 
$
987 

 

Net Debt/Total Capitalization

 

 35% 

 

 25% 

 

 27% 

 

 

 

 

 

 

 

 

 

 

(1)   Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow, EBITDA and diluted CFPS are non-GAAP financial measures.

(2)   Adjusted net income and adjusted diluted EPS in 2012 exclude $1,192.4 million (after-tax) in non-cash ceiling test impairments and $0.2 million (after-tax) unrealized gain on derivative contracts. Both are non-GAAP financial measures.

(3)   Excludes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.

 

 

(Slide 19)
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

185.2 Bcf

$5.06

29%

2014

Swaps

  54.8 Bcf

$4.43

-

 

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)

Ultra Petroleum

 

$0.86

Range Resources

 

$0.89

Southwestern Energy Company

 

$0.93

Cabot Oil & Gas

 

$0.98

Chesapeake Energy

 

$1.05

Forest Oil

 

$1.05

Noble Energy

 

$1.06

EOG Resources

 

$1.19

Anadarko Petroleum

 

$1.39

SM Energy

 

$1.45

Devon Energy

 

$1.49

Cimarex Energy

 

$1.56

Pioneer Natural Resources

 

$1.72

Newfield Exploration

 

$1.84

Apache

 

$1.92

Sandridge Energy

 

$2.10

Marathon

 

$2.16

Occidental Petroleum

 

$2.18

Murphy

 

$2.22

Denbury Resources

 

$3.87

 

This slide also contains a bar graph comparing SWN to its competitors in terms of Finding & Development Cost per Mcfe (3 year average).

 

 

 

 

 

Finding & Development Cost

 

 

per Mcfe

 

 

(3 year average)

Range Resources

 

$0.87

Southwestern Energy Company

 

$1.05

Cabot Oil & Gas

 

$1.30

Ultra Petroleum

 

$1.83

Devon Energy

 

$1.94

Cimarex Energy

 

$2.09

Chesapeake Energy

 

$2.21

EOG Resources

 

$2.23

Noble Energy

 

$2.29

Pioneer Natural Resources

 

$2.34

Marathon

 

$2.36

Anadarko Petroleum

 

$2.50

Denbury Resources

 

$2.62

SM Energy

 

$2.83

Newfield Exploration

 

$3.05

Sandridge Energy

 

$3.32

Occidental Petroleum

 

$3.35

Murphy

 

$3.44

Forest Oil

 

$3.56

Apache

 

$3.87

 

Source:  Public filings

Note: All data as of December 31, 2009, 2010 and 2011.  APC - Anadarko Petroleum, APA - Apache, COG - Cabot Oil & Gas, CHK - Chesapeake Energy, XEC - Cimarex Energy, DNR - Denbury Resources, DVN - Devon Energy, EOG - EOG Resources, FST - Forest Oil, MRO - Marathon Oil, MUR - Murphy Oil, NFX - Newfield Exploration, NBL - Noble Energy, OXY - Occidental Petroleum, PXD - Pioneer Natural Resources, RRC - Range Resources, SD - Sandridge Energy, SM - SM Energy, SWN - Southwestern Energy, UPL - Ultra Petroleum.

 

Lifting Cost per Mcfe defined as lease operating expenses plus production taxes divided by production.

 

        F&D Cost per Mcfe defined as the three-year sum of costs incurred in natural gas and oil exploration and development divided by the three-year sum of reserve additions from extensions and discoveries, improved recovery, revisions and purchases.

 

 

 (Slide 21)

ArkLaTex 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 22)
New Brunswick, Canada Exploration Project

This slide contains a map of the Province of New Brunswick, Canada.  The acreage on which the company has obtained licenses to explore is highlighted on the map: Marysville (2,309,247 acres) and Cocagne (209,271 acres).  The McCully Field, Stoney Creek Field, M&NE Pipeline and the Green Road G-41 well are denoted on the map.    

 

 

*  SWN currently holds exploration licenses to over 2.5 million acres within the Maritimes Basin

*  Principal targets are the conventional and unconventional sandstone and shale reservoirs of the Horton Group (Frederick Brook Shale)

*  Oil and gas production from fields along southern flank:

 

* McCully - reserves 190 bcfg

 

* Stoney Creek - cum 800,000 bo, 30 bcfg

*  3-year initial exploration license to complete work program

 

*  $47MM total work commitment with options for multiple 5-year extension leases

 

 

 

(Slide 23)

Fayetteville Shale - Horizontal Well Performance

 

Time Frame

Wells Placed on Production

Average IP Rate (Mcf/d)

30th-Day Avg Rate (# of wells)

60th-Day Avg Rate (# of wells)

Avg Lateral Length

1st Qtr 2007

 

58

 1,261 

 

1,066

(58)

958

(58)

2,104

2nd Qtr 2007

 

46

 1,497 

 

1,254

(46)

1,034

(46)

2,512

3rd Qtr 2007

 

74

 1,769 

 

1,510

(72)

1,334

(72)

2,622

4th Qtr 2007

 

77

 2,027 

 

1,690

(77)

1,481

(77)

3,193

1st Qtr 2008

 

75

 2,343 

 

2,147

(75)

1,943

(74)

3,301

2nd Qtr 2008

 

83

 2,541 

 

2,155

(83)

1,886

(83)

3,562

3rd Qtr 2008

 

97

 2,882 

 

2,560

(97)

2,349

(97)

3,736

4th Qtr 2008

(1)

74

 3,350 

(1)

2,722

(74)

2,386

(74)

3,850

1st Qtr 2009

(1)

120

 2,992 

(1)

2,537

(120)

2,293

(120)

3,874

2nd Qtr 2009

 

111

 3,611 

 

2,833

(111)

2,556

(111)

4,123

3rd Qtr 2009

 

93

 3,604 

 

2,624

(93)

2,255

(93)

4,100

4th Qtr 2009

 

122

 3,727 

 

2,674

(122)

2,360

(120)

4,303

1st Qtr 2010

(2)

106

 3,197 

(2)

2,388

(106)

2,123

(106)

4,348

2nd Qtr 2010

 

143

 3,449 

 

2,554

(143)

2,321

(142)

4,532

3rd Qtr 2010

 

145

 3,281 

 

2,448

(145)

2,202

(144)

4,503

4th Qtr 2010

 

159

 3,472 

 

2,678

(159)

2,294

(159)

4,667

1st Qtr 2011

 

137

 3,231 

 

2,604

(137)

2,238

(137)

4,985

2nd Qtr 2011

 

149

 3,014 

 

2,328

(149)

1,991

(149)

4,839

3rd Qtr 2011

 

132

 3,443 

 

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 

 

2,579

(79)

2,157

(43)

4,974

4th Qtr 2012

 

111

 3,962 

 

2,834

(109)

2,497

(70)

4,784

 

Note: Data as of December 31, 2012.

 

 

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. 2,090 MMcf/d as of December 31, 2012.  Periods of production affected by pipeline and heat related curtailment issues are denoted.

 

*  Gross operated production of approx. 2,090 MMcf/d as of December 31, 2012. 

*  2012 Fayetteville Shale F&D cost of $2.53/Mcf.

 

 

(Slide 24)

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  2,693  2,228  1,413  539 
100  2,606  2,195  1,404  539 
200  2,492  2,054  1,289  487 
300  2,372  1,951  1,203  437 
400  2,200  1,763  1,088  370 
500  2,044  1,620  959  320 
600  1,915  1,488  847  257 
700  1,733  1,323  714  199 
800  1,579  1,177  599  155 
900  1,431  1,046  484  114 
1,000  1,256  892  374  72 
1,100  1,119  738  289  44 
1,200  1,009  657  229  29 
1,300  885  542  171  15 
1,400  776  457  117  9 
1,500  633  324  66  5 

 

Note:  Data as of December 31, 2012. Excludes wells with mechanical problems (31).

 

(Slide 25)

Drilling & Completion Major Cost Categories

Average 2013 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
$
607 

Rig

 277 

OCTG

 228 

Environmental & Restoration

 141 

Drilling Fluids

 135 

Directional Drilling

 108 

Wellhead & Surface Equipment

 112 

Other

 34 

Water Treatment/Disposal

 118 

Supervision

 91 

Surface Rentals

 107 

Location

 97 

Wireline

 70 

Rentals

 26 

Coil Tubing

 85 

D&C Fluids

 77 

Bits

 45 

Cementing

 47 

Fuel & Water

 63 

Trucking & Transportation

 171 

Formation Evaluation

 18 

Special Services

 28 

Land & Damages

 40 

Major Cost Categories
$
2,725 

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

 

 

(Slide 26)

Water Demand: Perspective

 

The graphs contained in this slide compare the daily statewide demand for water in Arkansas by source to the average daily amount used by Southwestern Energy by source.

 

Statewide Demand:

11,500 million gallons/day

33% Ground Water

66% Surface Water

 

SWN Operations Demand:

10 million gallons/day (600 Wells/year)

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 usage.

 

Source: U.S. Geological Survey, Central Arkansas Water, Southwestern Energy Company estimates.

Shallow Ground Water (SGW) – Ground water recovered from shallow formations during the air drilling process. 

Flow Back Water (FBW) – Frac Fluid that is recovered from the well after the fracture stimulation. 

Produced Water (PW) – Natural formation water that is returned to the surface throughout the producing life of the well. 

 

 

(Slide 27)

U.S. Gas Consumption and Sources

This slide displays U.S. dry gas production versus U.S. gas consumption in Bcf from 1975 to present. Net imports for the same period are also given.  U.S. gas production rising in recent years.

Source: EIA

 

(Slide 28)
U.S. Electricity Consumption

This line graph shows U.S. electricity consumption in billion kilowatt-hours per month from 1990 to present.

Source:  Edison Electric Institute

 

(Slide 29)

U.S. Electricity Generation

This slide contains a chart showing Electricity Generation by Energy Source as a percentage of total.

Total 4,100 Billion kWh in 2011.

 

Energy Source

% 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 30)
U.S. Gas Drilling and Prices

This line graph denotes the number of rigs drilling for gas and the gas price in dollars per MMBtu through the period 2000 to present.

Source:  Baker Hughes, Bloomberg

 

(Slide 31)
Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1997 to present.

Source:  Bloomberg

 

 (Slide 32)

Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods. One such non-GAAP financial measure is net cash flow. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred. These adjusted amounts are not a measure of financial performance under GAAP.

 

 

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

 

 

$3.25 Gas

 

$3.50 Gas

$3.75 Gas

 

 

$85.00 Oil

 

$85.00 Oil

$85.00 Oil

 

 

($ in millions)

Net cash provided by operating activities

 

$1,650 - $1,660

 

$1,750 - $1,760

$1,850 - $1,860

Add back (deduct):

 

 

 

 

 

Assumed change in operating assets and liabilities

 

--

 

--

--

Net cash flow

 

$1,650 - $1,660

 

$1,750 - $1,760

$1,850 - $1,860

 

 

 

 

 

 

 

 

 

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

 

 

(Slide 33)

Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

 

 

 

 

 

 

 

 

 

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:

 

 

 

 

 

 

 

Impairment of natural gas & oil properties (net of taxes)

 1,192,412 

 

 3.42 

 

 558,305 

 

 1.62 

Unrealized gain on derivative contracts (net of taxes)

 (167)

 

--

 

--

 

--

Adjusted net income
$
485,181 

 
$
1.39 

 
$
522,655 

 
$
1.52 

 

 

(Slide 34)

Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA

EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry.  EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12 Months Ended December 31,

 

2012

 

2011

 

2010

 

2009

 

2008

 

2007

 

2006

 

2005

 

2004

 

2003

 

2002

 

($ in thousands)

Net income (loss)

$(707,064)

(1)

$  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)

(2)

413,221

 

391,659

 

(16,363)

(5)

350,999

 

135,855

 

99,399

 

86,431

 

59,778

 

28,372

(7)

8,708

  Depreciation, depletion and amortization

2,750,327

(3)

704,511

 

590,332

 

1,401,470

(6)

414,460

 

294,500

 

151,795

 

96,641

 

74,919

 

56,833

 

54,095

EBITDA

$2,078,920

 

$1,779,576

 

$1,612,272

 

$1,368,095

 

$1,362,309

 

$675,402

 

$414,509

 

$345,872

 

$255,265

 

$151,413

 

$98,580

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Net income (loss) includes after tax full cost ceiling impairments of our natural gas and oil properties of $1,192.4 million.

(2) 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.

(3) Depreciation, depletion and amortization includes $1,939.7 million for non-cash ceiling impairments of our natural gas and oil properties.

(4) 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.

(5) 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.

(6) Depreciation, depletion and amortization includes the $907.8 million non-cash ceiling impairment of our natural gas and oil properties recorded in Q1 2009. 

(7) 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

 

 

 

 

$3.25 Gas

 

$3.50 Gas

 

$3.50 Gas

 

Midstream Services Segment(1)

 

 

$85.00 Oil

 

$85.00 Oil

$85.00 Oil

 

 

 

($ in millions)

Net income (loss)attributable to SWN

 

$460-$470

 

$525-$535

 

$585-$595

 

$170-$175

Add back:

 

 

 

 

 

 

 

 

    Provision for income taxes

 

306-313

 

350-357

 

390-397

 

113-117

    Interest expense

 

27-29

 

26-28

 

25-27

 

13-15

    Depreciation, depletion and amortization

 

880-890

 

880-890

 

880-890

 

55-57

EBITDA

 

$1,680-$1,690

 

$1,780-$1,790

 

$1,880-$1,890

 

$355-$360

 

 

 

Note that the information contained on this slide constitutes a "Forward-Looking Statement".