8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): November 5, 2013

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation)

1-08246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 125, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)

(281) 618-4700

(Registrant's telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

        o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

The information in this report, including Exhibit 99.1 attached hereto, shall not be deemed to be "filed" for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that Section, and shall not be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Section 7 - Regulation FD

Item 7.01 Regulation FD Disclosure.

On November 5 2013, Southwestern Energy Company (the "Company") will make a presentation available to investors.  The presentation includes adjusted diluted earnings per share ("Adjusted Diluted EPS"), net cash provided by operating activities before changes in operating assets and liabilities ("Net Cash Flow"), net income before impairment of natural gas and oil properties and unrealized loss (gain) on derivative contracts (net of taxes) ("Adjusted Net Income"), earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA"), and earnings before interest, taxes, depreciation, depletion, amortization, and unrealized gains (losses) on derivatives ("Adjusted EBITDA") .  Net Cash Flow, Adjusted Net Income, Adjusted Diluted EPS, EBITDA, and Adjusted EBITDA are non-GAAP measures that are reconciled on slides 33, 34 and 35 of the presentation, respectively.  A copy of the presentation is furnished herewith as Exhibit 99.1. 

All statements in the presentation, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Exhibits.  The following exhibits are being furnished as part of this Report.

Exhibit Number	Description
99.1	Transcript of slideshow accompanying the November 2013 presentation.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SOUTHWESTERN ENERGY COMPANY
Dated: November 5, 2013	By:	/s/    R. CRAIG OWEN
	Name:	R. Craig Owen
	Title:	Senior Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Transcript of slideshow accompanying the November 2013 presentation.

EX-99

EXHIBIT 99.1

Slide Presentation dated November 2013

(Cover)
SWN

November2013Update

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 November1, 2013

NYSE: SWN
Shares of Common Stock Outstanding	351,752,517
Market Capitalization	$13,436,000,000
Institutional Ownership	92.6%
Management and Board Ownership	2.0%
52-Week Price Range	$32.09  (1/10/13) - $39.91 (8/1/13)

Investor Contacts

Steve Mueller
President and Chief Executive Officer

Phone:	(281) 618-4800
Fax:	(281) 618-4820

Brad 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 October 31, 2013.

(Slide 3)
About Southwestern

This slide contains a bar graph that compares SWN to its competitors in terms of US Lower 48gas production over time. Graph depicts SWN’s overall ranking as of the following time periods: 2Q13, 2Q12, 2Q11, 2Q10, 2Q09, and 2Q08.  SWN is 5th overall as of 2Q13.

	Production	Period
XOM	3,581	2Q13
CHK	3,055	2Q13
APC	2,647	2Q13
DVN	1,969	2Q13
SWN	1,756	2Q13
BP	1,533	2Q12
COP	1,516	2Q12
SWN	1,508	2Q12
ECA	1,402	2Q11
SWN	1,347	2Q11
BHP	1,319	2Q10
CVX	1,137	2Q10
RDS/A	1,089	2Q10
SWN	1,077	2Q10
WPX	1,007	2Q09
COG	997	2Q09
EQT	959	2Q09
EOG	928	2Q09
APA	861	2Q09
SWN	815	2Q09
OXY	792	2Q08
RRC	713	2Q08
QEP	625	2Q08
UPL	622	2Q08
EP	505	2Q08
SWN	487	2Q08
Antero	433	2Q08
SM	430	2Q08
CNX	424	2Q08
XCO	414	2Q08
NBL	404	2Q08
PXD	400	2Q08
NFX	351	2Q08
XEC	341	2Q08
MRO	316	2Q08
SD	277	2Q08
FCX	263	2Q08
KWK	241	2Q08
CLR	238	2Q08
CXO	205	2Q08
EGN	202	2Q08

*  2012:           * 4,018 Bcfe of Reserves           * Production – 565 Bcfe           * Reserve Life – 7.1 Years
*  2013:
	* 70%+ of Capex Allocated to Drilling
*  2007 – 2012:
	*  38% Annual Production Growth * 23% Annual Reserve Growth * 325 Reserve Replacement(1) * $1.36 per Mcfe F&D Cost (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 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)
Third Quarter 2013 Highlights

* Third Quarter 2013 Highlights
	* Production up 19%, due to strong Fayetteville and Marcellus results.
	*  Recorded highest quarterly Adjusted 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.
	*  Currently active on more than 4 New Ventures projects with over 1.3 million exploration acres.
	*  Strong balance sheet and financial position as of September 30, 2013:
		*  Debt-to-book capitalization ratio of 35%
		*  $1.5 billion revolving credit facility with $243 million drawn.
		*  Cash and restricted cash on hand of approximately $19 million

*  Strong Growth and Low-Cost Operations Set the Stage for a Record 2013
		*  2013 projected capital investment program of $2.25 billion.
		* 2013 production projected to grow 16%.
(1) (2)	Adjusted EBITDA and discretionary cash flow are non-GAAP financial measures. Cash operating costs for the nine months ended September 30, 2013 include lease operating expenses ($0.85/Mcfe), general and administrative expenses ($0.23/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
Adjusted EBITDA ($MM)(1)	$ 99	$ 151	$ 255	$ 346	$ 415	$ 675	$ 1,362	$ 1,368	$ 1,612	$ 1,775	1,638
F&D Cost ($/Mcfe)(2)	$ 1.01	$ 1.18	$ 1.34	$ 1.51	$ 2.08	$ 2.70	$ 1.70	$.91	$ 1.24	$ 1.34	$ 2.08

Note: Reserve data includes reserve revisions.

(1)Adjusted EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of Adjusted 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, the Marcellus Shale, and New Ventures.

Exploration & Production Segment

* 2012:	4,018 Bcfe of Reserves
	Production – 565.0 Bcfe
* 2013  Est. Production: 653-655 Bcfe

New Ventures

* Brown Dense – Approx. 475,000 net acres

* Colorado – Approx. 302,000 net acres

* New Brunswick – Approx. 2.5 million acres

* Undisclosed Ventures – Approx. 595,000 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: 337,300  (4/30/13)

*Southwestern’s E&P segment operates in Arkansas, Texas, Pennsylvania, Louisiana, Oklahoma, and New Brunswick.

*Midstream Services segment provides marketing and gathering services for the E&P business.

Notes: ArkLaTex acreage excludes 124,653 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	Forecast
Corporate & Other	$ 32	$ 16	$ 17	$ 30	$ 73	$ 69	$ 55	$ 90
Midstream Services	49	107	183	214	271	161	165	160
Drilling Rigs	94	5	-	-	-	-	-	-
Property Acquisitions	18	2	-	-	1	-	-	93
Cap. Expense & Other E&P	62	77	153	190	185	220	269	321
Leasehold & Seismic	70	166	149	114	215	257	196	129
Development Drilling	421	1,110	1,255	1,257	1,370	1,486	1,257	1,387
Exploration Drilling	196	20	39	4	5	14	139	70
Total	$ 942	$ 1,503	$ 1,796	$ 1,809	$ 2,120	$ 2,207	$ 2,081	$ 2,250

Additionally, this slide contains a pie chart of the company's planned 2013 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Fayetteville Shale	40%
Marcellus Shale	39%
Midstream	7%
New Ventures	10%
Corp/Other	4%
Ark-La-Tex	<1%

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

* 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.

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 map 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.

*	We hold approximately 337,300net acres in Northeast Pennsylvania.
*	At September 30, 2013, our gross operated production from the Marcellus Shale was approximately 661 MMcf/d from 151 operated horizontal wells.
*	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 82,  8 and 61 for each county, respectively. The small table contained in this slide contains quarterly drilling statistics as follows:

Time Period	30thDay Avg. Rate (# of Wells)		Average CLAT (ft)	Avg RE-RE (Rig Days)	Avg CWC ($MM)
2010 3rd Qtr	1,405	(1)	2,927	22.6	$5.8
2010 4th Qtr	5,584	(6)	3,805	19.8	$7.1
2011 1st Qtr	5,052	(3)	3,864	18.1	$6.6
2011 2nd Qtr	6,114	(7)	4,780	13.4	$6.7
2011 4th Qtr	5,284	(5)	4,129	18.8	$6.0
2012 1st Qtr	7,327	(2)	4,009	13.2	$6.0
2012 2nd Qtr	3,859	(17)	3,934	12.9	$6.0
2012 3rd Qtr	4,493	(8)	4,380	13.2	$5.7
2012 4th Qtr	4,606	(22)	3,830	15.9	$7.0
2013 1st Qtr	5,356	(21)	4,712	11.0	$7.0
2013 2nd Qtr	5,530	(37)	4,654	11.6	$6.6
2013 3rd Qtr	4,540	(15)	5,404	11.5	$7.3

(Slide 10)

Marcellus Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 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 wells), 9-12 stages (49 wells), 13-18 stages (66 wells), and greater than 18 stages (32 wells). The production data is compared to 4 Bcf, 8 Bcf, 12 Bcf, and 16 Bcf typecurves from the company's reservoir simulation shale gas model.  The graph also notes that multiple wells are shut-in for simultaneous operations over the 700-750 day period.

Additionally, this slide contains a line graph displaying gross operated production in MMcf/d for the Marcellus Shale from September 1, 2010 to September 30, 2013.

Gross operated production of approx. 611MMcf/d as of September 30, 2013.

Notes: Data as of September 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 September 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 or equal to5MMcf/d, and greater than or equal to 5MMcf/d from 9/30/12 to 9/30/13.

*  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 to 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".

(Slide 12)
Fayetteville Shale - Continuous Improvement

	2007	2008	2009	2010	2011	2012	9M13
Days to Drill	17.5	13.6	11.7	10.9	7.9	6.7	6.0
Lateral Length (feet in length)	2,657	3,619	4,100	4,528	4,836	4,819	5,166
Well Cost ($ in millions)	$2.9	$3.0	$2.9	$2.8	$2.8	$2.5	$2.3
F&D Cost ($ per Mcf)	$2.39	$1.44	$0.80	$1.04	$1.11	$2.53	-
Production (in Bcf)	53.5	134.5	243.5	350.2	436.8	485.5	360.4
Reserves (in Bcf)	716	1,545	3,117	4,345	5,104	2,988	-

	9M 2013 Change Over 2007
Days to Drill	-66%
Lateral Length (feet in length)	+94%
Well Cost ($ in millions)	-21%
Production (in Bcf)	+807%
Reserves (in Bcf)	+317%	(2012 Change over 2007)

*  Continuous improvement in our Fayetteville Shale operations – completed lateral length has increased 94%  since 2007 while total well costshave decreased 21%.

*  Vertical integration and contiguous acreage position allow us significant economies of scale and operating flexibility.

Notes: 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.

*	SWN’s Fayetteville Shale gathering system is one of the largest in the U.S.
*	At September 30, 2013, gathering approximately 2.3 Bcf per day through 1,920 miles of gathering lines and 539,000 horsepower of compression equipment.
*	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 September 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 bo and 180 Mcf, second well Garrett peak of 301 bc and 1,720 Mcf, third well BML peak of 421 bc and 3,900 Mcf, fouth well Johnson-Vert (shut in), fifth well Dean- vertical peak of 214 bc  and 1,207 Mcf, sixth well Doles peak of 435 bc and 2,500 Mcf, seventh well Dean-Hzl (completing), eighth well Sharp-Vert peak of 600 bo and 1,300 Mcf, ninth well Hollis-Vert (flowing back), tenth well McMahen- Vert (completing), and eleventh well Plum Creek Vert (drilling).

* SWN currently holds 475,000 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 and wet gas window in Upper Jurassic age, kerogen-rich carbonate in southern Arkansas and northern Louisiana.

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

*  Latest vertical well (Sharp) had peak rate of over 800 Boe/d; three additional vertical wells in various stages of drilling/completion/production.

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

(Slide 15)
Outlook for 2013

*  Production target of 653-655 Bcfe in 2013 (estimated growth of ~16%).

	2012	2013 Guidance
	Actual	NYMEX Price Assumption
	$2.79 Gas	$3.50 Gas	$3.75 Gas	$4.00 Gas
	$94.94 Oil	$85.00 Oil	$85.00 Oil	$85.00 Oil
Adj. Net Income	$485.2 MM(1)	$690-$700 MM	$740-$750 MM	$790-$800 MM
Adj. Diluted EPS	$1.39(1)	$1.97-$2.00	$2.11-$2.14	$2.26-$2.29
EBITDA	$1,638.3 MM(1)	$1,990-$2,000 MM	$2,075-$2,085 MM	$2,160-$2,170 MM
Net Cash Flow  (2)	$1,598.9 MM	$1,880-$1,890 MM	$1,950-$1,960 MM	$2,040-$2,050 MM
CapEx	$2,080.5 MM	$2,250 MM	$2,250 MM	$2,250 MM
Debt %	35%	34%-36%	33%-35%	32%-34%

(1) Adjusted net income, adjusted diluted EPS and Adjusted EBITDA exclude non-cash ceiling test impairments and unrealized gains and losses on derivative contracts. All are non-GAAP financial measures. See explanation and reconciliation on pages 34 and 35.

(2) Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow is a non-GAAP financial measure. See explanation and reconciliation on page 33.

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

	Nine Months Ended September 30,		Year Ended December 31,
	2013	2012	2012	2011	2010
	($ in millions, except per share amounts)		($ in millions, except per share amounts)
Revenues	$ 2,464.1	$ 1,952.6	$ 2,715.0	$ 2,952.9	$ 2,610.7
Adjusted EBITDA (1)	1,460.4	1,159.3	1,638.3	1,775.2	1,612.3
Adjusted Net Income (2)	515.5	330.0	485.2	637.8	604.1
Net Cash Flow (3)	1,445.5	1,142	1,598.9	1,766.0	1,579.7
Adjusted Diluted EPS(2)	$ 1.47	$ 0.95	$ 1.39	$ 1.82	$ 1.73
Diluted CFPS (3)	$ 4.12	$ 3.28	$ 4.59	$ 5.05	$ 4.52
Production (Bcfe)	480.3	415.1	565.0	500.0	404.7
Realized Avg. Gas Price ($/Mcf)	$ 3.63	$ 3.33	$ 3.44	$ 4.19	$ 4.64
Realized Avg. Oil Price ($/Bbl)	$ 105.05	$ 102.89	$ 101.54	$ 94.08	$ 76.84
Realized Avg. NGL Price ($/Bbl)	$ 44.20	---	---	---	---
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)	$ 1,076	$ 1,024	$ 1,041	$ 969	$ 972
Net Debt/Total Capitalization	35%	32%	35%	25%	27%

(1)   Adjusted EBITDA is a non-GAAP financial measure. See explanation and reconciliation of Adjusted 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 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	285.7 Bcf	$4.76	45%
2014	Swaps	232.7 Bcf	$4.41	-

Quarter	Bcf Hedged	NYMEX Fixed Price
1Q 2013	0-25	$5.00
1Q 2013	25-45	$5.13
2Q 2013	0-25	$5.00
2Q 2013	25-45	$5.13
2Q 2013	45-70	$4.22
3Q 2013	0-25	$5.00
3Q 2013	25-45	$5.13
3Q 2013	45-85	$4.22
4Q 2013	0-25	$5.00
4Q 2013	25-45	$5.13
4Q 2013	45-85	$4.22
1Q 2014	0-4	$4.51
1Q 2014	4-57	$4.40
2Q 2014	0-4	$4.51
2Q 2014	4-57	$4.40
3Q 2014	0-4	$4.51
3Q 2014	4-57	$4.40
4Q 2014	0-4	$4.51
4Q 2014	4-57	$4.40

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)
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 reserve revisions).

(Slide 21)

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		2,366	(102)	2,069	(102)	4,942
2nd Qtr 2013		126	3,625		2,233	(126)	1,980	(125)	5,165
3rd Qtr 2013		89	4,979		2,493	(61)	2,146	(31)	5,490

Note: Data as of September 30, 2013.

(1) The significant increase in the average initial production rate for the fourth quarter of 2008 and the subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline. 

(2) In the first quarter of 2010, the company’s results were impacted by the shift of all wells to “green completions” and the mix of wells, as a large percentage of wells were placed on production in the shallower northern and far eastern borders of the company’s acreage.

Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2004 to January 2014. Gross operated production of approx. 2,030 MMcf/d as of September 30, 2013.  Periods of production affected by heat and pipeline curtailment issues are denoted.

*  Gross operated production of approx. 2,030 MMcf/d as of September 30, 2013

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

(Slide 22)

Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 30, 2013, 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 2Bcf, 3Bcf, and 4Bcf 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	3,010	2,520	1,669	666
100	2,935	2,508	1,670	666
200	2,800	2,351	1,534	601
300	2,692	2,264	1,460	573
400	2,573	2,123	1,366	517
500	2,461	2,006	1,259	471
600	2,285	1,829	1,122	394
700	2,135	1,695	1,012	342
800	1,981	1,545	903	295
900	1,839	1,411	771	230
1,000	1,672	1,253	654	175
1,100	1,513	1,076	529	135
1,200	1,352	955	428	92
1,300	1,202	820	333	57
1,400	1,081	728	271	38
1,500	960	613	203	24

Note:  Data as of September 30, 2013. Excludes wells with mechanical problems (31).

(Slide 23)

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	Percent of Total
	(in thousands)
Fracture Stimulation	$ 625	25%
Rig	226.3	9%
OCTG	195	8%
Environmental & Restoration	79	3%
Drilling Fluids	135	5%
Directional Drilling	87	4%
Wellhead & Surface Equipment	113	5%
Other	69	3%
Water Treatment/Disposal	249	10%
Supervision	69	3%
Surface Rentals	91	4%
Location	56	2%
Wireline	87	4%
Rentals	56	2%
Coil Tubing	63	3%
Bits	48	2%
Cementing	49	2%
Fuel & Water	49	2%
Trucking & Transportation	2	0%
Formation Evaluation	31	1%
Special Services	25	1%
Land & Damages	43	2%
Contingency	6	0%
Major Cost Categories	$ 2,452

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

(Slide 24)

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

A box accompanying the graphs states:

SWN Operations Less than 0.09% of State’s water usage

SWN Operations Demand:

10 million gallons/day (600 Wells/year)

25% Recycle/Reused Water SGW, FBW, & PW

75% Surface Water

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 25)

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 26)
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 (Peak of 146 bo and 59 mcf) is denoted.

*  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

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

*  Additional tests planned for 1Q 2014.

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

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

(Slide 28)

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 4,060 Billion kWh in 2012.

Energy Source	% of Total Electricity Generation
Coal	37%
Natural Gas	31%
Nuclear	19%
Hydroelectric	7%
Renewables (1)	5%
Other (2)	1%

Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2011 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 34% of their capacity.

Electricity Generation Capacities	Trailing 12 Month Generation (3)	2011 Capacity	Unused Capacity
Nuclear	87,442	101,400	14%
Coal	175,441	319,200	45%
Natural Gas	138,989	413,100	66%

1. Geothermal, solar, wood, waste, and wind

2. Petroleum and others gases

3. March 2012 – February 2013

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.

	9 Months Ended September 30,
	2013	2012
	(in thousands)
Net cash provided by operating activities	$ 1,377,518	$ 1,192,477
Add back (deduct):
Change in operating assets and liabilities	68,028	(50,520)
Net cash flow	$ 1,445,546	$ 1,141,957

dd back
	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	$1,880 - $1,890	$1,950 - $1,960	$2,040 - $2,050
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--
Net cash flow	$1,880 - $1,890	$1,950 - $1,960	$2,040 - $2,050

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.

	9 Months Ended		9 Months Ended
	September 30, 2013		September 30, 2012
	($ in thousands)	(per share)	($ in thousands)	(per share)
Net income (loss)attributable to SWN	$ 559,013	$ 1.59	$ (351,481)	$ (1.01)
Add back (deduct):
Impairment of natural gas & oil properties (net of taxes)	---	---	682,039	1.96
Unrealized gain  on derivative contracts (net of taxes)	(43,562)	$ (0.12)	(558)	---
Adjusted net income	$ 515,451	$ 1.47	$ 330,000	$ 0.95

	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 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: Adjusted 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 Adjusted EBITDA with historical net income.

	9 Months Ended September 30,
	2013	2012
Net income (loss)	$ 559,013	$ (351,481)	(2)
Add back:
Net interest expense	29,317	26,305
Provision (benefit) for income taxes	373,457	(210,481)	(3)
Depreciation, depletion and amortization	571,268	1,685,865	(4)
Less: Unrealized gains (losses) on derivatives (1)	72,664	892
Adjusted EBITDA	$ 1,460,391	$ 1,159,316

	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)	(8)	$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
Adjusted 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 Adjusted 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 $682.0 million.

(3) Provision (benefit) for income taxes includes the ($408.4) million income tax benefit related to the non-cash ceiling impairments of our natural gas and oil properties.

(4) Depreciation, depletion and amortization includes $1,090.5 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	$690-$700		$740-$750	$790-$800	$170-$175
Add back:
Provision for income taxes	460-467		493-500	527-533	113-117
Interest expense	39-41		38-40	37-39	13-15
Depreciation, depletion and amortization	795-805		795-805	795-805	55-57
EBITDA	$1,990-$2,000		$2,075-$2,085	$2,160-$2,170	$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".