1

Jefferies 2013 Global Energy ConferenceJefferies 2013 Global Energy Conference

November 13, 2013November 13, 2013

2

Forward Looking StatementsForward Looking Statements

The material included herein which is not historical fact co nstitutes “forward-looking statements” within themeaning of Section 27A of the Securities Act of 1933, as amend ed, and Section 21E of the SecuritiesExchange Act of 1934, as amended. These opinions, forecasts , scenarios and projections relate to, amongother things, estimates of future capital expenditures, le vels and costs of drilling activity, estimatedproduction rates or forecasts of growth thereof, hydrocarb on reserve quantities and values, potential oil andgas reserves expressed as “net resource potential”, assumpti ons as to future hydrocarbon prices, liquidity,cash flows, operating results, availability of capital, in ternal rates of return, net asset values, drillingschedules and potential growth rates of reserves and produc tion, all of which are forward-lookingstatements. These forward-looking statements are general ly accompanied by words such as “estimated”,“projected”, “potential”, “anticipated”, “forecasted” or other words that convey the uncertainty of futureevents or outcomes. Although the Company believes that such forward-looking statements are reasonable,the matters addressed reflect management’s current plans a nd assumptions, are subject to numerous risksand uncertainties, many of which are beyond the Company’s co ntrol, and certain of which are set out in ourmost recent Form 10-K and Form 10-Q filed with the SEC. The Com pany can give no assurance thatestimates and projections contained in such statements wil l prove to have been correct. For reconciliationsof non-GAAP financial measures, see our website at www.swiftenergy.com .

Cautionary Note Regarding Potential Reserves Disclosures – Current SEC rules regarding oil and gasreserve information allow oil and gas companies to disclose not only proved reserves, but also probable andpossible reserves that meet the SEC’s definitions of such te rms. In this presentation, we refer to estimates ofresource “potential” or “EUR” (estimated ultimate recovery quantities) or “IP” (initial production rates) otherdescriptions of volumes potentially recoverable, which in addition to reserves generally classifiable asprobable and possible include estimates of reserves that do not rise to the standards for possible reserves,and which SEC guidelines strictly prohibit us from includin g in filings with the SEC. These estimates are bytheir nature more speculative than estimates of proved rese rves and are subject to greater uncertainties, andaccordingly the likelihood of recovering those reserves is subject to substantially greater risk.

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Swift Energy – An Eagle Ford StorySwift Energy – An Eagle Ford Story

� High quality Eagle Ford position primed to deliver liquids rich production and reserves growth

� “Manufacturing” high value Eagle Ford acreage generates:• Cash Flow Growth• Earnings Growth• Lower Financial Leverage• Predictable Project Returns• Lower Operating Expenses & Finding Costs

� Multi-year, de-risked inventory of projects

� Eagle Ford results improving compared to 2012• Initial Well Performance up >10%• 2-year Cumulative Recovery Estimates Up >10%• Well Costs Reduced >10%

4

AgendaAgenda

� Focused Approach

� South Texas Development

� Central Louisiana Divestiture

� Financial Overview

� Summary

5

A Focused ApproachA Focused Approach

• Deploying >80% of capital in the Eagle Ford Shale i n South Texas

• Current investment in crude oil and liquids rich projects• Substantial inventory of natural gas projects for future development

• Divesting Central Louisiana Assets to fund expansion of South Texas operations

• Will reduce financial leverage through organic cash flow growth

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Swift Energy Operating AreasSwift Energy Operating Areas

Total CompanyTotal Company2012 Production: 32.0 MBoe/d2012 YE Proved Reserves: 192.1 MMBoe

Central Louisiana Area*2012 Production: 2.5 MBoe/d2012 YE Proved Reserves: 20.4 MMBoe

Central Louisiana Area*2012 Production: 2.5 MBoe/d2012 YE Proved Reserves: 20.4 MMBoe

Central Louisiana Area*2012 Production: 2.5 MBoe/d2012 YE Proved Reserves: 20.4 MMBoe

South Bearhead Creek

Burr FerryMastersCreek

Southeast Louisiana Area2012 Production: 6.1 MBoe/d2012 YE Proved Reserves: 15.0 MMBoe

Southeast Louisiana Area2012 Production: 6.1 MBoe/d2012 YE Proved Reserves: 15.0 MMBoe

Southeast Louisiana Area2012 Production: 6.1 MBoe/d2012 YE Proved Reserves: 15.0 MMBoe

Lake Washington

Bay de CheneTexas Area2012 Production: 23.4 MBoe/d2012 YE Proved Reserves: 156.7 MMBoe

Texas Area2012 Production: 23.4 MBoe/d2012 YE Proved Reserves: 156.7 MMBoe

Texas Area2012 Production: 23.4 MBoe/d2012 YE Proved Reserves: 156.7 MMBoe

Artesia Wells& Sun TSH

AWP

Fasken

Southwest Colorado - Niobrara

*Includes Brookeland field reserves and production that was sold May 2, 2013.

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South Texas DevelopmentSouth Texas Development

8

MEXICO

South TexasSouth Texas

Webb CountyFasken

LaSalle CountyArtesia WellsSun TSH

McMullen CountySMRNorth AWPSouth AWP

Eagle Ford PlayHydrocarbon Types

OILCONDENSATE

GAS

9

A

A’

AWP

DeWitt Co.

Artesia

Wells

Fasken

South Texas – Lower Eagle Ford HPVSouth Texas – Lower Eagle Ford HPV

Petrophysics: Boucher and JD; Mapping: DWH%Ro line from Cardneaux…

Zone: EF Lower HPV. (Feet)Zone: EF Lower Avg. Porosity (%)Zone: EF Lower Avg. Sw (%)Zone: EF Lower Avg. Vcl (%)Zone: EF Lower Avg. TOC (%)Zone: EF Lower Isopach (feet)

Legend:

� Note: Buda TVDSS (feet) shown on some wells

HPV = Hydrocarbon Pore Volume

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Eagle Ford Regional SW - NE: Webb to DeWitt CountiesEagle Ford Regional SW - NE: Webb to DeWitt Counties

A A’

HPV = IP: 509 Bopd;

975 Mcfd

IP: 178 Bcpd;

4,038 Mcfd

HPV = 10.58.9

20.315.64.4

Carden EF: IPHPV = 13.5

11.125.2

245

Fasken 'A': IP

HPV = 8.68

25.17.44.2

PCQ EF: IP HPV = 18.111.6

16.616.44.1

Fasken ‘A’ 1P Carden EF: 1P PCQ: 1P

Webb Co. LaSalle Co. McMullen Co. DeWitt Co.

Zone: EF Lower HPV. (Feet)Zone: EF Lower Avg. Porosity (%)Zone: EF Lower Avg. Sw (%)Zone: EF Lower Avg. Vcl (%)Zone: EF Lower Avg. TOC (%)Zone: EF Lower Isopach (feet)

Legend:

� Flattened on Lower Eagle Ford� Note IP values represent an average of EF

wells within ~1 mile of well shown� Density (DPH) curve fill for GT 6% porosity

IP: 6,053 Mcfd IP: 564 Bcpd;

2,636 Mcfd

Well log data displayed in this presentation is own ed or controlled by TGS and/or Swift Energy Compan y; interpretation is that of Swift Energy Company.

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South Texas South Texas

� Continued Focus on Highest Value Acreage Position• High Value Eagle Ford dry gas acreage earned or held

� Efficiencies are Improving Margins• 3-D Seismic facilitates proper placement of laterals• Logging well laterals results in:

� Optimized placement of frac stages � Improved frac performance� Often reduces the number of frac stages needed to complete a well

• Drilling times and costs are being reduced• Frac execution times and costs are being reduced

� Marketing Infrastructure • Firm transportation and secondary interruptible connection in place for all areas

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Strong Eagle Ford Position Driving Future GrowthStrong Eagle Ford Position Driving Future Growth

Exploiting high value Eagle

Ford acreage

� ~ 340 MMBoe of Net Resource Potential

� ~80% of capital in 2011-2013 directed to South Texas

Experienced South Texas

Operator with large inventory

remaining

� 107 Horizontal EF wells drilled

� 590 drilling locations remaining with current well spacing

2013 performance ahead of 2012

levels

� IP Rates� EURs� Well Costs

13

0

200

400

600

800

1,000

1,200

1,400

2012 2013 2012 2013

Artesia N AWP

Eagle Ford

Improving Actual Eagle Ford Initial RateImproving Actual Eagle Ford Initial RateB

oepd

20% Increase

18% Increase

YTD YTD

14

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2012 2013 2012 2013

Artesia N AWP

2013 Eagle Ford Actual Average Drilling & Completion Cost Performance vs. 20122013 Eagle Ford Actual Average Drilling & Completion Cost Performance vs. 2012

MM

$

10% Decrease

19% Decrease

YTD YTD

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Drilling Cost Reduction - Eagle Ford WellsDrilling Cost Reduction - Eagle Ford Wells

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5M

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16

0

5000

10000

15000

20000

25000

0

5

10

15

20

25

Average M

DD

ays/

10K

FT

Companies

Day/10 FT Average MD

BENCHMARKING2013 La Salle County EFBENCHMARKING2013 La Salle County EF

***Data from Dodson's Database

Average Days/10K Ft

17

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

0

10

20

30

40

50

60

Average M

DDay

s/10

K F

T

Companies

Days/10K FT Average MD

Benchmarking2013 McMullen County EFBenchmarking2013 McMullen County EF

***Data from Dodson's Database

Average Days/10K Ft

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South Texas Completion Cost EvolutionSouth Texas Completion Cost Evolution

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013

2012 $4,197M

2013 $3,664M

M$

19

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

2010 2011 2012 2013

Tota

l Spe

nd $

MM

Average Drilling & Completion Costs $M/Well and Ave rage Lateral Length

Quarterly Eagle Ford Drill & Completion SpendingQuarterly Eagle Ford Drill & Completion Spending

5,674’ Av.Lateral Length

YTD

$11,600 $9,480 $8,680 $7,4944,280’ Av.

Lateral Length5,270’ Av.

Lateral Length5,671’ Av.

Lateral Length

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Eagle Ford Proved ReservesEagle Ford Proved Reserves

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2010 2011 2012

Net

MB

oeNet Liq Net Gas

21

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

2010 2011 2012 2013

Liquids Gas

Eagle Ford Net Boepd Production Eagle Ford Net Boepd Production

YTD

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South Texas Focus Will Improve Cost Structure South Texas Focus Will Improve Cost Structure

Area3Q13

LOE/Boe

3Q13 Taxes, Transportation &

Processing Costs/Boe

South Texas $4.57 $4.13

Central Louisiana $11.09 $6.50

Southeast Louisiana $21.66 $13.65

Total Corporate $7.55 $5.72

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Central Louisiana DivestitureCentral Louisiana Divestiture

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Masters Creek:+ 48,000 acres+ 500 Bopd net production

Austin Chalk ‘B developmentAustin Chalk ‘A developmentSaratoga Chalk development

+ 2,200 acres TMS potential

South Bearhead Creek

Burr FerryMasters Creek

Central LouisianaCentral Louisiana

South Bearhead Creek:+ 7,100 acres+ 354 Bopd net production

Horizontal Wilcox development+ 5,400 acres TMS potential

Burr Ferry:+ 140,000 acres+ 65,000 mineral acres+ 1,500 Bopd net production

Horizontal Austin Chalk “B’ development

Horizontal Lower Wilcox development

+ 140,000 acres TMS potential

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Financial OverviewFinancial Overview

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CapitalizationCapitalization

All Sr Notes rated B+/B3 Corporate Rating B+/B2

Credit Statistics

Net Debt/LTM EBITDA 2.6x 2.9xDebt/Capitalization 46.9% 51.1%

Debt/YE Proved Reserves ($/Boe) $4.77 $5.83

Cash $0 0% $0 0%

Bank Borrowings 39 2% 243 11%

71/8% Sr Notes due 2017 250 13% 250 11%

87/8% Sr Notes due 2020 222 11% 222 10%

77/8% Sr Notes due 2022 405 21% 405 18%

Net Debt 917 47% 1,120 51%

Stockholders’ Equity 1,037 53% 1,072 49%

Capitalization $1,954 100% $2,192 100%

Liquidity $411 $207

$ in Millions As of

Dec. 31, 2012

$ in MillionsAs of

Sept. 30, 2013

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**Based on Company guidance provided on October 31, 2013 press release and prepared assuming NYMEX strip pricing of $95.00 crude oil and $3.50 n atural gas pricing for 2013

*For presentation purposes, development includes fa cilities expenditures

2013 Spending by Activity

$515 MM-$520 MM**$515 MM-$520 MM**

DevelopmentDevelopment

FacilitiesFacilities

DiscretionaryDiscretionary

Prospect Costs/Seismic Prospect Costs/Seismic

Historical Spending$ MM

0

100

200

300

400

500

600

700

800

2007 2008 2009 2010 2011 2012

Acquisition ProspectExploration Development*

2013 Capital Expenditure Budget2013 Capital Expenditure Budget

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SummarySummary

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Building Momentum, Growing the Eagle Ford and Improving PerformanceBuilding Momentum, Growing the Eagle Ford and Improving Performance

� Aggressive Eagle Ford development will afford more predictable results, higher quality earnings and consistent cash flow growth

� “Manufacturing” high value Eagle Ford acreage

� Focus on high return Eagle Ford delivers:• Lower Leverage, Cash Flow & EPS Growth• Predictable Project Returns• Lower Operating Expenses & Finding Costs

� Multi-year, de-risked inventory of projects

� Eagle Ford results improving compared to 2012• Initial Well Performance up >10%• 2-year Cumulative Recovery Estimates Up >10%• Well Costs Reduced >10%