Exhibit 99.1

EXHIBIT 99.1

Slide Presentation dated March 2014

(Cover)
SWN

March 2014 Update

NYSE: SWN

The upper left side of this slide contains a SWN employee assisting with a volunteer project. The upper right side of this slide contains a scenic view of the Marcellus countryside. The bottom left side of this slide contains a drilling rig operating in the Marcellus Shale play. The bottom right side of this slide contains a compressed natural gas (CNG) station with a price of $1.60 gallon of gas equivalent (GGE) located in Damascus, Arkansas.

(Slide 1)
Southwestern Energy Company

General Information

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

Market Data as of March 1, 2014


NYSE: SWN
Shares of Common Stock Outstanding	352,940,302
Market Capitalization	$14,590,000,000
Institutional Ownership	93.5%
Management and Board Ownership	2.0%
52-Week Price Range	$34.27 (2/28/13) - $43.29 (2/24/14)

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 February 27, 2014.

(Slide 3)
About Southwestern

This slide contains a bar graph that compares SWN to its competitors in terms of US Lower 48 gas production over time. Graph depicts SWN’s overall ranking as of the following time periods: 4Q13, 4Q12, 4Q11, 4Q10, 4Q09, 4Q08, and 4Q07. SWN is 4th overall as of 4Q13.


	Production	Period
XOM	3,445	4Q13
CHK	2,946	4Q13
APC	2,643	4Q13
SWN	1,920	4Q13
DVN	1,895	4Q12
SWN	1,628	4Q12
COP	1,493	4Q11
BP	1,467	4Q11
SWN	1,448	4Q11
BHP	1,275	4Q10
COG	1,268	4Q10
ECA	1,216	4Q10
SWN	1,209	4Q10
CVX	1,171	4Q09
EQT	1,030	4Q09
RDS/A	1,013	4Q09
WPX	971	4Q09
SWN	966	4Q09
EOG	873	4Q08
OXY	762	4Q08
RRC	756	4Q08
SWN	624	4Q08
AR	611	4Q07
UPL	596	4Q07
APA	583	4Q07
QEP	525	4Q07
CNX	511	4Q07
NBL	458	4Q07
LINE	441	4Q07
SM	429	4Q07
XCO	400	4Q07
SWN	370	4Q07
XEC	352	4Q07
PXD	346	4Q07
NFX	323	4Q07
MRO	297	4Q07
CLR	263	4Q07
FCX	249	4Q07
EP	218	4Q07
CXO	207	4Q07

* 2013:
	* 6,976 Bcfe of Reserves * Production – 657Bcfe * Reserve Life – 10.6 Years

* 2014:
	* 70%+ of Capex Allocated to Drilling

* 2008 – 2013:
	* 28% Annual Production Growth * 26% Annual Reserve Growth * 370% Reserve Replacement(1) * $1.11 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)
2013 Highlights and 2014 Outlook


* Full-year 2013 Highlights
	* Record production of 657 Bcfe, up 16%, due to strong Fayetteville and Marcellus results
	* Record total proved reserves of approximately 7.0 Tcfe, up 74%
	* Record adjusted earnings, adjusted EBITDA (1) and discretionary cash flow (1) primarily driven by low cash operating costs (2) and the continued strong growth from our Midstream business
	* Achieved the lowest finding cost (3) in company history and the third highest reserve replacement (3) in company history
	* Currently testing multiple New Venture ideas
	* Strong balance sheet and financial position as of December 31, 2013:
		* Debt-to-book capitalization ratio of 35%
		* $2 billion revolving credit facility with $283 million drawn at year-end


* Strong Growth and Low-Cost Operations Set the Stage for a Record 2014
		* 2014 projected capital investment program of $2.3 billion.
		* 2014 production projected to grow 14%.




(1) (2) (3)	Adjusted EBITDA and discretionary cash flow are non-GAAP financial measures. Cash operating costs for the twelve months ended December 31, 2013 include lease operating expenses ($0.86/Mcfe), general and administrative expenses ($0.24/Mcfe), taxes other than income taxes ($0.10/Mcfe) and net interest expense ($0.05/Mcfe). 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 5)
Proven Track Record

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

		2003		2004		2005		2006		2007		2008		2009		2010		2011		2012		2013
Production (Bcfe)		41		54		61		72		113		195		300		405		500		565		657
Average Realized Gas Price ($/Mcf)	$	4.20	$	5.21	$	6.51	$	6.55	$	6.80	$	7.52	$	5.30	$	4.64	$	4.18	$	3.44	$	3.65
Proved Reserves (Bcfe)		503		646		827		1,026		1,450		2,185		3,657		4,937		5,893		4,018		6,976
Adjusted EBITDA ($MM)(1)	$	151	$	255	$	346	$	415	$	675	$	1,362	$	1,383	$	1,602	$	1,774	$	1,638	$	1,997
F&D Cost ($/Mcfe) (2)	$	1.18	$	1.34	$	1.51	$	2.08	$	2.70	$	1.70	$	0.91	$	1.24	$	1.34	$	2.08	$	0.62

(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


* 2013:	6,976 Bcfe of Reserves
	Production – 657 Bcfe
* 2014 Est. Production: 740-752 Bcfe

New Ventures

* Brown Dense – Approx. 459,000 net acres

* Colorado – Approx. 302,000 net acres

* New Brunswick – Approx. 2.5 million acres

* Undisclosed Ventures – Approx. 696,000 net acres

Fayetteville Shale

* Reserves: 4,795 Bcf (69%)

* Production: 486 Bcf (74%)

* Net Acres: 905,684 (12/31/13)

Ark-La-Tex

* Reserves: 215 Bcfe (3%)

* Production: 18 Bcfe (3%)

* Net Acres: 152,937 (12/31/13)

Marcellus Shale

* Reserves: 1,963 Bcf (28%)

* Production: 151 Bcf (23%)

* Net Acres: 292,446 (12/31/13)

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

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


Notes:	ArkLaTex acreage excludes 124,220 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, 2013. Production is a total annual amount for 2013.

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):


									2014
	2006	2007	2008	2009	2010	2011	2012	2013	Plan
Corporate & Other	$ 33	$ 16	$ 17	$ 30	$ 73	$ 69	$ 55	$ 25	$ 55
Midstream Services	49	107	183	214	271	161	165	158	119
Drilling Rigs	94	5	-	-	-	-	-	76	93
Property Acquisitions	18	2	-	-	1	-	-	93	-
Cap. Expense & Other E&P	62	77	153	190	185	220	269	224	270
Leasehold & Seismic	70	166	149	114	215	257	196	94	206
Development Drilling	421	1,110	1,255	1,257	1,370	1,483	1,257	1,457	1,328
Exploration Drilling	195	20	39	4	5	17	139	108	254
Total	$ 942	$ 1,503	$ 1,796	$ 1,809	$ 2,120	$ 2,207	$ 2,081	$ 2,235	$ 2,325

Additionally, this slide contains a pie chart of the company's planned 2014 capital investments by area of operation, summarized as follows:


	% of Total
	Capital Investments
Fayetteville Shale	39%
Marcellus Shale	33%
Midstream	6%
New Ventures	8%
Brown Dense	8%
Corp/Other	6%
Ark-La-Tex	<1%


* E&P capital program heavily weighted to low-risk development drilling in 2014.

* Plan to invest approximately $1 billion in the Fayetteville Shale and $800 million in the Marcellus Shale in 2014 (including Midstream).

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 2014 for Lycoming County (7 wells), Bradford County (41 wells), Susquehanna County (27 wells), and Wyoming, Sullivan, and Tioga Counties (8 wells). Lines trace the Transco, Tennessee Gas, Millennium, Stagecoach, PVR Line, and Bluestone transmission pipelines.


*	We hold approximately 292,000 net acres in Northeast Pennsylvania.

*	At December 31, 2013, our gross operated production from the Marcellus Shale was approximately 700 MMcf/d from 171 operated horizontal wells.

*	We plan to drill 80 to 85 operated horizontal wells in 2014.

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

(Slide 9)

Marcellus Gross Production

This slide contains a line graph displaying gross operated production in MMcf/d for the Marcellus Shale from September 1, 2010 to December 31, 2013.

Gross operated production of approx. 698 MMcf/d as of December 31, 2013.

The small table contained in this slide contains quarterly drilling statistics as follows:


Time Period	30th Day 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	4,512	(17)	5,404	11.5	$7.3
2013 4th Qtr	10,119	(7)	5,887	10.2	$7.1

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

(Slide 10)

Marcellus Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 31, 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 (73 wells), and greater than 18 stages (45 wells). The production data is compared to 4 Bcf, 8 Bcf, 12 Bcf, and 16 Bcf type curves from the company's reservoir simulation shale gas model. The graph also notes that multiple wells are shut-in for simultaneous operations over the 700-750 day period.

Notes: Data as of December 31, 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 December 31, 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 to 5MMcf/d, and greater than or equal to 5MMcf/d.

* SWN holds approx. 906,000 net acres in the Fayetteville Shale play.

* SWN discovered the Fayetteville Shale and has first mover advantage – average acreage cost of $320 per acre with a 15% royalty and average working interest of 74%.

* We plan to drill approximately 460 to 470 operated wells in 2014.

* Nine of the top ten highest wells based on initial producing rates were drilled in the second half of 2013.

Notes: Data as of December 31, 2013. 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	2013
Days to Drill	17.5	13.6	11.7	10.9	7.9	6.7	6.2
Lateral Length (feet in length)	2,657	3,619	4,100	4,528	4,836	4,819	5,356
Well Cost ($ in millions)	$2.9	$3.0	$2.9	$2.8	$2.8	$2.5	$2.4
F&D Cost ($ per Mcf)	$2.39	$1.44	$0.80	$1.04	$1.11	$2.53	$0.45
Production (in Bcf)	54	135	244	350	437	486	486
Reserves (in Bcf)	716	1,545	3,117	4,345	5,104	2,988	4,795


	2013 Change Over 2007
Days to Drill	-65%
Lateral Length (feet in length)	+102%
Well Cost ($ in millions)	-17%
Production (in Bcf)	+800%
Reserves (in Bcf)	+570%

* Continuous improvement in our Fayetteville Shale operations – completed lateral length has more than doubled since 2007 while total well costs have decreased 17%.

* 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.

(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 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 peak of 37 bc and 428 Mcf, tenth well McMahen- Vert peak of 17 bc and 299 Mcf, eleventh well Plum Creek Vert peak of 75 bo and 184 Mcf, twelfth well Milstead- Vert (testing), and thirteenth well Plum Creek 23-Vert (completing).

* SWN currently holds 459,000 net acres in Lower Smackover Brown Dense play. Total land cost of approx. $483 per acre; 84% NRI; most leases have 3-year terms and 3 to 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.

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

(Slide 14)
Outlook for 2014

* Production target of 740-752 Bcfe in 2014 (estimated growth of ~14%).


	2013	2014 Guidance
	Actual	NYMEX Price Assumption
	$3.65 Gas	$3.75 Gas	$4.00 Gas	$4.25 Gas
	$96.77 Oil	$90.00 Oil	$90.00 Oil	$90.00 Oil
Adj. Net Income(1)	$703.9 MM	$700-$710 MM	$740-$750 MM	$785-$795 MM
Adj. Diluted EPS(1)	$2.00	$1.99-$2.02	$2.11-$2.14	$2.24-$2.27
EBITDA(1)	$1,997.2 MM	$2,100-$2,110 MM	$2,165-$2,175 MM	$2,235-$2,245 MM
Net Cash Flow (2)	$1,983.8 MM	$2,050-$2,060 MM	$2,110-$2,120 MM	$2,175-$2,185 MM
CapEx	$2,235 MM	$2,325 MM	$2,325 MM	$2,325 MM
Debt %	35%	31%-33%	30%-32%	29%-31%

(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 33, 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 32.

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

(Slide 15)
The Road to V+


* Invest in the Highest PVI Projects.

* 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 16)
Appendix

(Slide 17)
Financial & Operational Summary


	Year Ended December 31,
	2013	2012	2011

	($ in millions, except per share amounts)
Revenues	$ 3,371.1	$ 2,730.0	$ 2,951.3
Adjusted EBITDA (1)	1,997.2	1,638.3	1,774.0
Adjusted Net Income (2)	703.9	486.7	634.4
Net Cash Flow (1)	1,983.8	1,598.9	1,766.0
Adjusted Diluted EPS (2)	$ 2.00	$ 1.39	$ 1.81
Diluted CFPS (1)	$ 5.65	$ 4.59	$ 5.05

Production (Bcfe)	656.8	565.0	500.0
Realized Avg. Gas Price ($/Mcf)	$ 3.65	$ 3.44	$ 4.18
Realized Avg. Oil Price ($/Bbl)	$ 103.32	$ 101.54	$ 94.08

Finding Cost ($/Mcfe) (3)	$ 0.62	$ 2.08	$ 1.34
Reserve Replacement (%) (3)	501%	163%	292%

Total Debt/Proved Reserves ($/Mcfe)	$ 0.28	$ 0.42	$ 0.23
Total Debt/Avg. Daily Production ($/Mcfe)	$ 1,084	$ 1,081	$ 981
Total Debt/Total Capitalization	35%	35%	25%

(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 exclude non-cash ceiling test impairments and gains (losses) on derivatives, net of settlement, and 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 18)
Gas Hedges in Place Through 2015

This slide contains a bar chart detailing gas hedges in place by quarter for year 2014 and year 2015. A summary of these gas hedges is as follows:


			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2014	Swaps	455.8 Bcf	$4.34	61%
2015	Swaps	119.5 Bcf	$4.40	-


Quarter	Bcf Hedged	NYMEX Fixed Price
1Q 2014	0-4.5	$4.51
1Q 2014	4.5-57.4	$4.40
1Q 2014	57.4-94.3	$4.22
1Q 2014	94.3-107.3	$4.42
2Q 2014	0-4.6	$4.51
2Q 2014	4.6-58.0	$4.40
2Q 2014	58.0-95.3	$4.22
2Q 2014	95.3-115.3	$4.42
3Q 2014	0-4.6	$4.51
3Q 2014	4.6-58.7	$4.40
3Q 2014	58.7-96.4	$4.22
3Q 2014	96.4-116.6	$4.42
4Q 2014	0-4.6	$4.51
4Q 2014	4.6-58.7	$4.40
4Q 2014	58.7-96.4	$4.22
4Q 2014	96.4-116.6	$4.42
1Q 2015	0-29.5	$4.40
2Q 2015	29.5-59.3	$4.40
3Q 2015	59.3-89.4	$4.40
4Q 2015	89.4-119.5	$4.40

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

(Slide 19)

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 20)
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 12/31/13 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 2Q 2014.

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

(Slide 21)
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 22)

Fayetteville Shale - Horizontal Well Performance


Time Frame		Wells Placed on Production	Average IP Rate (Mcf/d)		30th-Day Avg Rate (# of wells)		60th-Day Avg Rate (# of wells)		Avg Lateral Length
1st Qtr 2007		58	1,261		1,066	(58)	958	(58)	2,104
2nd Qtr 2007		46	1,497		1,254	(46)	1,034	(46)	2,512
3rd Qtr 2007		74	1,769		1,510	(72)	1,334	(72)	2,622
4th Qtr 2007		77	2,027		1,690	(77)	1,481	(77)	3,193
1st Qtr 2008		75	2,343		2,147	(75)	1,943	(74)	3,301
2nd Qtr 2008		83	2,541		2,155	(83)	1,886	(83)	3,562
3rd Qtr 2008		97	2,882		2,560	(97)	2,349	(97)	3,736
4th Qtr 2008	(1)	74	3,350	(1)	2,722	(74)	2,386	(74)	3,850
1st Qtr 2009	(1)	120	2,992	(1)	2,537	(120)	2,293	(120)	3,874
2nd Qtr 2009		111	3,611		2,833	(111)	2,556	(111)	4,123
3rd Qtr 2009		93	3,604		2,624	(93)	2,255	(93)	4,100
4th Qtr 2009		122	3,727		2,674	(122)	2,360	(120)	4,303
1st Qtr 2010	(2)	106	3,197	(2)	2,388	(106)	2,123	(106)	4,348
2nd Qtr 2010		143	3,449		2,554	(143)	2,321	(142)	4,532
3rd Qtr 2010		145	3,281		2,448	(145)	2,202	(144)	4,503
4th Qtr 2010		159	3,472		2,678	(159)	2,294	(159)	4,667
1st Qtr 2011		137	3,231		2,604	(137)	2,238	(137)	4,985
2nd Qtr 2011		149	3,014		2,328	(149)	1,991	(149)	4,839
3rd Qtr 2011		132	3,443		2,666	(132)	2,372	(132)	4,847
4th Qtr 2011		142	3,646		2,606	(142)	2,243	(142)	4,703
1st Qtr 2012		146	3,319		2,421	(146)	2,131	(146)	4,743
2nd Qtr 2012		131	3,500		2,515	(131)	2,225	(131)	4,840
3rd Qtr 2012		105	3,857		2,816	(105)	2,447	(105)	4,974
4th Qtr 2012		111	3,962		2,815	(111)	2,405	(111)	4,784
1st Qtr 2013		102	3,301		2,366	(102)	2,069	(102)	4,942
2nd Qtr 2013		126	3,625		2,233	(126)	1,975	(126)	5,165
3rd Qtr 2013		89	4,597		2,658	(87)	2,327	(85)	5,490
4th Qtr 2013		97	4,877		2,856	(89)	2,583	(60)	5,976

Note: Data as of December 31, 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. 2,011 MMcf/d as of December 31, 2013. Periods of production affected by heat and pipeline curtailment issues are denoted.

* Gross operated production of approx. 2,011 MMcf/d as of December 31, 2013

* 2013 Fayetteville Shale F&D cost of $0.45/Mcf

(Slide 23)

Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 31, 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 2 Bcf, 3 Bcf, and 4 Bcf type curves 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	3,099	2,344	1,534	611
100	3,052	2,620	1,776	735
200	2,943	2,490	1,655	663
300	2,826	2,392	1,570	626
400	2,694	2,245	1,469	571
500	2,583	2,124	1,355	527
600	2,474	2,012	1,262	470
700	2,329	1,879	1,156	414
800	2,157	1,716	1,036	353
900	2,010	1,571	912	304
1,000	1,873	1,431	801	250
1,100	1,691	1,238	662	183
1,200	1,543	1,123	562	142
1,300	1,391	985	454	100
1,400	1,239	868	357	64
1,500	1,089	726	275	38

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

(Slide 24)

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, 2013, gathering approximately 2.3 Bcf per day in the Fayetteville Shale through 1,947 miles of gathering lines and 558,155 horsepower of compression equipment.

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

*	Adjusted EBITDA (1) of approximately $376 million in 2013 and projected to be stable for 2014..

Note: Map as of December 31, 2013.

(1) EBITDA is a non-GAAP financial measure.

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

(Slide 25)

Drilling & Completion Major Cost Categories

Average 2014 Fayetteville Shale Well Cost Estimate

This slide displays the estimated average 2014 major well cost categories as a proportion to the total average well costs.


	Average 2014 Fayetteville Shale Well Cost Estimate	Percent of Total
	(in thousands)
Fracture Stimulation	$ 582	22%
Rig	299	11%
OCTG	218	8%
Environmental & Restoration	92	4%
Drilling Fluids	147	6%
Directional Drilling	101	4%
Wellhead & Surface Equipment	60	2%
Other	79	3%
Water Treatment/Disposal	255	10%
Supervision	77	3%
Surface Rentals	103	4%
Location	65	2%
Wireline	86	3%
Rentals	110	4%
Coil Tubing	64	2%
Bits	56	2%
Cementing	52	2%
Fuel & Water	57	2%
Trucking & Transportation	2	1%
Formation Evaluation	35	1%
Special Services	27	1%
Land & Damages	52	2%
Contingency	6	1%
Major Cost Categories	$ 2,625

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

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 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 4,020 Billion kWh (Nov 2012 – Oct 2013).


Energy Source	% of Total Electricity Generation
Coal	39%
Natural Gas	28%
Nuclear	19%
Hydroelectric	7%
Renewables (1)	6%
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 30% of their capacity.


Electricity Generation Capacities	Trailing 12 Month Generation (3)	2011 Capacity	Unused Capacity
Nuclear	88,818	101,400	12%
Coal	180,944	319,200	43%
Natural Gas	125,906	413,100	70%

Geothermal, solar, wood, waste, and wind

Petroleum and others gases

March 2012 – February 2013

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,
	2013	2012	2011	2010
		(in thousands)
Net cash provided by operating activities	$ 1,908,528	$ 1,653,942	$ 1,739,817	$ 1,642,585
Add back (deduct):
Change in operating assets and liabilities	75,272	(55,060)	26,201	(62,906)
Net cash flow	$ 1,983,800	$ 1,598,882	$ 1,766,018	$ 1,579,679


	2014 Guidance
	NYMEX Commodity Price Assumption
	$3.75 Gas	$4.00 Gas	$4.25 Gas
	$90.00 Oil	$90.00 Oil	$90.00 Oil
	($ in millions)
Net cash provided by operating activities	$2,050 - $2,060	$2,110 - $2,120	$2,175 - $2,185
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--
Net cash flow	$2,050 - $2,060	$2,110 - $2,120	$2,175 - $2,185

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 December 31,
	2013		2012		2011
	($ in thousands)	(per share)	($ in thousands)	(per share)	($ in thousands)	(per share)
Net income (loss)	$ 703,503	$ 2.00	($707,064)	($2.03)	$ 637,769	$ 1.82
Add back (deduct):						---
Impairment of natural gas & oil properties (net of taxes)	---	---	1,192,412	3.42	---	---
Adjustments due to discrete tax items (1)	12,997	0.04	---	---	---	---
(Gain) Loss on Certain derivatives, net of taxes	($12,636)	($0.04)	1,324	---	($3,398)	($0.01)
Adjusted net income	$ 703,864	$ 2.00	$ 486,672	$ 1.39	$ 634,371	$ 1.81

(1) Primarily relates to the exclusion of certain discrete tax adjustments that were recognized in the fourth quarter of 2013 due to a redetermination of deferred state tax liabilities to reflect updated state apportionment factors in Pennsylvania and the recognition of an income tax valuation allowance for state net operating losses. The company expects its 2014 effective income tax rate to be 40%.

(Slide 34)

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.


		12 Months Ended December 31,
	2013		2012			2011	2010		2009		2008	2007	2006	2005	2004	2003
		($ in thousands)
Net income (loss)	$703,503			$(707,064)	(2)	$ 637,769	$ 604,118		$ (35,650)	(5)	$567,946	$221,174	$162,636	$147,760	$103,576	$48,897
Add back:
Net interest expense	41,594			35,657		24,075	26,163		18,638		28,904	23,873	679	15,040	16,992	17,311
Provision (benefit) for income taxes	486,874			(443,139)	(3)	413,221	391,659		(16,363)	(6)	350,999	135,855	99,399	86,431	59,778	28,372	(8)
Depreciation, depletion and amortization	786,612			2,750,687	(4)	704,511	590,332	(10)	1,401,470	(7)	414,460	294,500	151,795	96,641	74,919	56,833
Less: Unrealized gains (losses) on derivatives (1)	21,380			(2,154)		5,600	10,083		(14,905)
Adjusted EBITDA	$1,997,203			$1,638,295		$1,773,976	$1,602,189		$1,383,000		$1,362,309	$675,402	$414,509	$345,872	$255,265	$151,413

(1) Unrealized gains (losses) were excluded from the Adjusted EBITDA calculation.

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

(3) 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.

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

(5) Net income (loss) includes the after tax $558.3 million non-cash ceiling impairments of our natural gas and oil properties recorded in Q1 2009.

(6) Provision (benefit) for income taxes includes the ($349.5) million income tax benefit related to the non-cash ceiling impairments of our natural gas and oil properties recorded in Q1 2009.

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

(8) Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principles.

The table below reconciles historical Adjusted EBITDA by operating segment with historical net income by operating segment with historical net income by operating segment for the fiscal year ended December 31, 2013.


	E&P	Midstream Services	Other	Total
(in thousands)
2013
Net Income (loss)	$ 508,548	$ 196,072	$ (1,117)	$ 703,503
Depreciation, depletion and amortization expense	735,215	50,940	457	786,612
Impairment of natural gas and oil properties	--	--	--	--
Gain on derivatives, net of settlement	(20,898)	(480)	(2)	(21,380)
Net interest expense	30,244	10,619	731	41,594
Provision for income taxes	368,320	119,223	(669)	486,874
Adjusted EBITDA	$ 1,621,429	$ 376,374	$ (600)	$ 1,997,203

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

(Slide 35)

Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted EBITDA

The table below reconciles forecasted EBITDA with forecasted net income for 2014, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2014, including current hedges in place:


	2014 Guidance

	NYMEX Commodity Price Assumption
	$3.75 Gas	$4.00 Gas		$4.25 Gas		Midstream Services Segment(1)
	$90.00 Oil	$90.00 Oil		$90.00 Oil
	($ in millions)
Net income attributable to SWN	$700-$710		$740-$750	$710-$720	$175-$180
Add back:
Provision for income taxes	467-473		493-500	523-530	117-120
Interest expense	33-35		32-34	31-33	9-11
Depreciation, depletion and amortization	885-895		885-895	885-895	52-54
EBITDA	$2,100-$2,110		$2,165-$2,175	$2,235-$2,245	$355-$360

(1)

Midstream Services segment results assume NYMEX commodity prices of $3.75 per Mcf for natural gas and $90.00 per barrel for crude oil for 2014.

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