1. business and industrial
2. energy
3. natural gas

Corporate Presentation
February 2015
Forward Looking Statements
The material included herein which is not historical fact constitutes “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. These opinions, forecasts, scenarios and projections relate to, among
other things, estimates of future commodity prices and operating and capital costs, capital expenditures,
levels and costs of drilling activity, estimated production rates or forecasts of growth thereof, hydrocarbon
reserve quantities and values, potential oil and gas reserves expressed as “net resource potential”,
assumptions as to future hydrocarbon prices, liquidity, cash flows, operating results, availability of
capital, internal rates of return, net asset values, drilling schedules and potential growth rates of reserves
and production, all of which are forward-looking statements. These forward-looking statements are generally
accompanied by words such as “estimated”, “projected”, “potential”, “anticipated”, “forecasted” or other
words that convey the uncertainty of future events or outcomes. Although the Company believes that such
forward-looking statements are reasonable, the matters addressed reflect management’s current plans and
assumptions, are subject to numerous risks and uncertainties, many of which are beyond the Company’s
control, and certain of which are set out in our most recent Form 10-K and Form 10-Q filed with the SEC. The
Company can give no assurance that estimates and projections contained in such statements will prove to
have been correct. For reconciliations of non-GAAP financial measures, see our website at
www.swiftenergy.com.
Cautionary Note Regarding Potential Reserves Disclosures – Current SEC rules regarding oil and gas
reserve information allow oil and gas companies to disclose not only proved reserves, but also probable and
possible reserves that meet the SEC’s definitions of such terms. In this presentation, we refer to estimates of
resource “potential” or “EUR” (estimated ultimate recovery quantities) or “IP” (initial production rates) other
descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as
probable and possible include estimates of reserves that do not rise to the standards for possible reserves,
and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates are by
their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and
accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
2
Swift Energy Overview
• High Quality Reserve Base
– 194 MMBoe YE 2014 proved reserves
– $1.94 Billion PV-10(1)
Central & SE Louisiana
Proved Reserves: ~36 MMBoe
4Q14 Production: 5,292 boe/d
~15% of Total Production
• Eagle Ford Core Operating Area
– ~70,000 net acres
– Over 520 identified locations targeting lower and
upper Eagle Ford
• Industry Leading Well Performance
– 14 consecutive wells at Fasken w/ IPs > 20MMcf/d
– 2 new Bracken AWP wells w/ IPs > 5,000 Boe/d
• 2015 Revised Capital Program
–
–
–
–
2015 budget of $110-$125 million
2015 production guidance of 11.4-11.6 MMBoe
Focus on capital discipline and operational flexibility
Over 230 locations economic at current prices
• Proactive Response Macro Environment
– Meaningful headcount reductions
– Significant drilling and completions price concessions
South Texas / Eagle Ford
Proved Reserves: ~158 MMBoe
4Q14 Production: 27,626 boe/d
~85% of Total Production
(1) Calculated using 2014 average SEC adjusted prices of $4.32 per Mcf of natural gas, $93.64 per barrel of oil and
$33.00 per barrel of NGL; net of $85.4 million in ARO.
3
Investment Highlights
Leader in the gas and gas condensate areas of the Eagle Ford
Significant inventory of repeatable, lower risk development projects
138 MMBoe of proved reserves in Eagle Ford
Management has drilled over 165 wells in the Eagle Ford
High Quality Eagle Ford
Focused Asset Base
•
•
•
•
Operational Control
• Operate over 98% of the fields in which we operate
• Minimal leasehold obligations to preserve asset base
• No long term rig, frac, or sand commitments
Track Record of
Finding Reserves
•
•
•
•
Focus on Efficient
Operations, Strong
Execution
• Delivering industry-leading well performance; 2 new Bracken wells IP > 5,000 boe/d
• Transferred Fasken technology and engineering design to core AWP gas and condensate acreage
• Maximizing capital efficiency and resource recovery through enhanced drilling and completion
techniques
Optimizing Cost
Structure and Liquidity
•
•
•
•
Reserve and production five-year CAGR of 15% in South Texas
Fasken EUR’s increased 20% in 2014
Production profile tracking above type curve in Fasken, AWP Gas, and Condensate acreage
Take advantage of opportunities to expand in core areas of expertise; recently added ~12,500
acres in core AWP gas acreage with option to lease additional ~17,000 more
Capital allocation targeted to protect balance sheet and liquidity
>25% headcount reductions since 1/1/14
Expect 15-30% reduction in various drilling and completion costs
Unit costs expected to continue to decline
4
Proactive Response to Current Market Downturn
• 2015 CapEx has been revised to $110MM to $125MM
– Midpoint is ~70% below 2014 levels
– Projected CapEx levels expected to yield 11.4 – 11.6 MMBoe of production
• Actively targeting reducing various costs (G&A, LOE, and Capex)
– Headcount down >25% since 1/1/14
– Ongoing efforts to reduce LOE
– Estimating a 15-30% reduction in Fasken/AWP drilling and completion costs
• Drilling activity focused on most promising opportunities
– Directed to the best commercial opportunities in the Eagle Ford
• Management and Board are proactively focused on behalf of all
of the Company’s constituents
5
Eagle Ford Operations
Locations
@ YE14
%
Gas
45
60
20
100%
100%
100%
>65%
79
80%
>30%
11
15
60%
57%
>15%
104
20%
>15%
County
Gross
Acres
Webb
8,302
McMullen
9,994
McMullen
3,355
McMullen
14,749
Artesia Lower EF
Oil Acreage
Condensate Acreage
La Salle
La Salle
4,849
4,933
39
43
40%
50%
Oro Grande
Gas Acreage
Gas Acreage Option
La Salle
McMullen
12,635
11,850
74
71
100%
100%
Area
Fasken
Lower Eagle Ford
Upper Eagle Ford
Olmos
AWP
Gas Acreage
Lower Eagle Ford
Condensate Acreage
Lower Eagle Ford
Olmos
Oil Acreage
Lower Eagle Ford
IRR(1)
SFY Acreage
(1) Pre-tax IRR; internal calculation using $55/bbl and $3.00/Mmcf using target 2015 well costs.
6
Demonstrated Eagle Ford Operational Excellence
30,000
Average Net Production (Boe/d)
28,800
24,000
Yearly wells drilled
140
17,497
18,000
43
6,000
35
1,294
0
2011
2012
2013
2014
Exit Rate
CapEx as % of Company Total
100%
14
0
2010
$12.0
2011
56%
2013
2014
Average Per Well Drill & Complete Cost ($MM)
9.2
$9.0
75%
2012
10.6
85%
49%
129
70
7,346
2010
165
89
105
14,180
12,000
50%
Cumulative Wells Drilled
175
8.2
7.6
64%
Target
54%
$6.0
25%
$3.0
0%
2010
2011
2012
2013
2014
$2011
2012
2013
2014
2015
7
Mcf
Drill & Complete Design Improving Results
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
0
Average Cumulative 300 Day Gas Production at Fasken
Enhanced Design(1)
Original Design
0
30
100,000
60
90
150
180
Days on Production
210
240
270
300
Average Cumulative 300 Day Production at AWP Oil
80,000
Boe
120
Enhanced Design(2)
60,000
Original Design
40,000
20,000
0
0
30
60
90
120
(1) Represents well drilled prior to 1Q14
(2) Represents wells drilled prior to 2Q14
150
Days on Production
180
210
240
270
300
8
Importance of Geo-Steering & Longer Laterals(1)
150’
Lateral
Length (ft)
Stages
PCQ EF 3H
Out of zone
3,300
10
PCQ EF 7H
In zone
6,400
19
Well
PCQ EF 7H
30’
150,000
1 Year Cumulative Production
120,000
Boe
Drilling
Path
PCQ EF 3H
90,000
PCQ EF 7H (New)
PCQ EF 3H (Old)
60,000
30,000
0
1
31
61
91
121
151
181
Normalized Days
211
241
271
301
331
(1) Graphics are for presentation purposes only and do not depict all relevant geologic and engineering information.
361
9
Benefits of Engineered Frac Design & Lateral Length(1)
 Open hole logging of laterals
Geometric Frac
• Identifies optimal frac gradient and brittle
zones
• Allows optimal grouping and perforating of
frac intervals
 Enhanced Fracture Complexity
• Multi-well frac treatments
• Lighter gel loading
• Improved near wellbore stimulated
Engineered Frac
reservoir volume (SRV)
 Increased fracture conductivity
• Added 50% proppant volume
• Aggressive proppant placement
(1) Graphics are for presentation purposes only and do not depict all relevant geologic and engineering information.
10
Eagle Ford Objectives
– Apply AWP and Fasken proven techniques and technology
to other Eagle Ford properties
– Greater drilling focus in 2015 on Fasken and AWP gas and
condensate acreage
– Further analyze and high grade Eagle Ford opportunities
– Additional improvement to economic returns through
lower costs and higher EURs
11
Fasken Lower Eagle Ford
Fasken Lower Eagle Ford Overview
•
•
•
•
•
Net Acres: 8,302
Well Spacing: 660’
Remaining Lower EF Locations at YE 2014: 45
Avg Working Interest: 64%
Avg Net Revenue Interest: 51%
Operational Excellence
Improved capital efficiencies w/ longer laterals and more sand
Increased IPs >100% since entry into the play (see map)
Increased Fasken per well reserve bookings by 20% in 2014
JV with Saka reinforces operational excellence of SFY
Expanded firm takeaway capacity to 160 MMcf/d
Drilled longest lateral to date of 7,614’, >100’ longer than
previous record
• Upper Eagle Ford well test to potentially add another growth
opportunity; Upper EF is over 100’ thick in Fasken
•
•
•
•
•
•
Dimmit
Fasken BD EF 14H
Avg IP: 20.6 MMcf/d
Fasken BD EF 15H
Avg IP: 22.5 MMcf/d
Fasken BD EF 16H
Avg IP: 23.3 MMcf/d
Fasken B EF 2H
Avg IP: 10.4 MMcf/d
Fasken B EF 7H
Avg IP: 7.6 MMcf/d
Fasken B EF 6H
Avg IP: 5.3 MMcf/d
Webb
Fasken A EF 6H
Avg IP: 11.4 MMcf/d
Fasken A EF 7H
Avg IP: 9.1 MMcf/d
Fasken B EF 5H
Avg IP: 8.3 MMcf/d
Fasken C 17H
Avg IP: 21.4 MMcf/d
Recent Results
Mexico
• Fasken AB EF 20H: IP – 22.2 MMcf/d
• Fasken AB EF 21H: IP – 20.1 MMcf/d
• Fasken AB EF 23H: IP – 20.5 MMcf/d
La Salle
Enhanced Design
Fasken C 18H
Avg IP: 20.2 MMcf/d
Fasken C 19H
Avg IP: 22.4 MMcf/d
Original Design
12
Fasken Economics: Exceptional Returns
35%
32%
IRR Competitive with Major U.S. Oil Plays(1)
30%
25%
18%
20%
15%
15%
12%
10%
10%
8%
8%
7%
5%
0%
SFY Fasken
Wolfcamp
Midland Basin
Eagle Ford
Oil
Utica
Condensate
Middle
Bakken
Breakeven Price Competitive with Major U.S. Gas Plays(2)
$5.25
$4.18
$4.50
$3.75
$3.00
Wattenberg PRB: Frontier
Niobrara
$2.62
$2.73
$3.08
$3.19
$4.39
TMS
$4.44
$4.56
Barnett
Core
Arkoma
Woodford
$3.59
$2.25
$1.50
$0.75
$0.00
SFY Fasken NE Marcellus
SW
Utica Dry
Dry Gas Core Marcellus
Gas Core
Dry Gas Core
Fayetteville Haynesville Central PA
Core
Core
Marcellus
(1) Source: Keybanc Capital Markets; Pre-tax IRR at $55/bbl and $3.00/Mcf
(2) Source: Keybanc Capital Markets; Henry Hub breakeven price for a 20% before-tax rate of return including
transportation expense and differential
13
Saka JV Demonstrates Fasken Value and Strong Operations
 Saka Energi Indonesia agreed to participate in the development of
approximately 8,300 acres in Fasken
 Saka paid $175 MM in total cash consideration for a 36% full
participating interest, effective January 1, 2014
• Consideration of $125mm in cash upfront and $50mm carry
 Carry of 18% of 8/8ths development costs to extend through
2016
 Partnership opens doors for other joint efforts in greater Eagle
Ford area
14
Increased Capacity Accommodates Fasken Growth(1)
Energy Transfer
Fasken
(1) Graphics are for presentation purposes only and do not depict all relevant information.
15
AWP Eagle Ford Gas Overview
AWP Eagle Ford Gas Overview
•
•
•
•
•
Net Acres: 9,994
Well Spacing: 660’
Remaining Locations at YE 2014: 79(1)
Avg Working Interest: 98%
Avg Net Revenue Interest: 73%
Operational Excellence
• Recent technical improvements
• Reduced drilling days to 31 vs 34 previously
• Reduced cost by $11 per foot
• Generational improvements in pad drilling
• Bracken 15H & 16H represent the largest initial rate
producing wells in the Company’s history
Recent Results
•
•
•
•
Bracken JV EF 15H
Avg IP: 5,345 Boe/d
Bracken JV EF 16H
Avg IP: 5,222 Boe/d
Bracken JV EF 5H
Avg IP: 1,855 Boe/d
Bracken JV EF 6H
Avg IP: 1,100 Boe/d
Bracken JV EF 15H: IP – 5,345 Boe/d; 31% liquids
Bracken JV EF 16H: IP – 5,222 Boe/d; 30% liquids
Bracken JV EF 13H: IP – 3,468 Boe/d; 19% liquids
Bracken JV EF 14H: IP – 2,935 Boe/d; 21% liquids
Bracken JV EF 8H
Avg IP: 2,285 Boe/d
Original Design
(1) AWP Lower Eagle Ford Gas locations only.
Bracken JV EF 13H
Avg IP: 3,468 Boe/d
Bracken JV EF 14H
Avg IP: 2,935 Boe/d
Whitehurst JV EF 1H
Avg IP: 1,882 Boe/d
Anthony JV EF 1H
Avg IP: 1,395 Boe/d
Enhanced Design
16
AWP Eagle Ford Condensate Overview
AWP Eagle Ford Condensate Overview
•
•
•
•
•
Net Acres: 3,355
Well Spacing: 660’
Remaining Locations at YE 2014: 11(1)
Avg Working Interest: 98%
Avg Net Revenue Interest: 73%
Operational Excellence
• Technical efficiencies maximizing returns
• Reduced drilling days by 15%
• Increased stage count and proppant per foot of CLAT
by 27% and 50%
• Generational improvements in pad drilling
Recent Results
• Whitehurst JV EF 3H: IP – 2,916 Boe/d; 47% liquids
• Whitehurst JV EF 4H: IP – 3,185 Boe/d; 48% liquids
Bracken JV EF 2H
Avg IP: 1,952 Boe/d
Bracken JV EF 10H
Avg IP: 2,157 Boe/d
Bracken JV EF 11H
Avg IP: 1,724 Boe/d
Whitehurst JV EF 4H
Avg IP: 3,185 Boe/d
Bracken JV EF 12H
Avg IP: 1,630 Boe/d
Original Design
(1) AWP Eagle Ford Condensate locations only
Whitehurst JV EF 3H
Avg IP: 2,916 Boe/d
Enhanced Design
17
AWP Eagle Ford Oil Overview
AWP Eagle Ford Oil Overview
•
•
•
•
•
Net Acres: 14,749
Well Spacing: 440’
Remaining Locations at YE 2014: 104(1)
Avg Working Interest: 100%
Avg Net Revenue Interest: 75%
Operational Excellence
• Technical efficiencies maximizing returns
• 14.8 drilling days in SMR / 17 days in PCQ
• Enhanced toe-prep method saving ~$120k/well
• Generational improvements in pad drilling
Recent Results
•
•
•
•
•
SMR EF 16H: IP – 1,339 Boe/d; 89% liquids
SMR EF 17H: IP – 1,401 Boe/d; 93% liquids
SMR EF 18H: IP – 1,280 Boe/d; 89% liquids
PCQ EF 22H: IP – 1,120 Boe/d; 74% liquids
PCQ EF 23H: IP – 1,180 Boe/d; 90% liquids
PCQ EF 14H
Avg IP: 1,302 Boe/d
PCQ EF 15H
Avg IP: 1,292 Boe/d
PCQ EF 16H
Avg IP: 1,042 Boe/d
SMR EF 10H
Avg IP: 1,562 Boe/d
SMR EF 1H
Avg IP: 1,000 Boe/d
PCQ EF 1H
Avg IP: 836 Boe/d
PCQ EF 2H
Avg IP: 698 Boe/d
PCQ EF 3H
Avg IP: 502 Boe/d
Original Design
(1) AWP Eagle Ford Oil locations only.
SMR EF 11H
Avg IP: 1,608 Boe/d
Enhanced Design
18
Louisiana Properties
Lake Washington Development
• Stable production stream and cash flows
• Numerous low-cost, high-return projects
• Recompletions and workovers
• Enhancements
• Sour crude oil production exploitation
• Cap rock exploitation
• Seismic exploitation
• 4Q14 Production: 3,700 boe/d, 87% liquids(1)
Burr Ferry
Masters Creek
Central Louisiana Properties
Acres
Mineral
Acres
Burr Ferry
140,000
Masters
Creek
48,000
South Bearhead
Creek
7,100
Texas
4Q14
Production
South Bearhead Creek
(Boe/d)
Development
65,000
973
Austin Chalk
Lower Wilcox
---
153
---
Mississippi
466
Austin Chalk
Saratoga Chalk
Gulf of Mexico
Lake Washington
Wilcox
(1) Includes Bay De Chene production of 116 boe/d
19
FINANCIAL OVERVIEW
Capitalization
$ in Millions
Dec. 31, 2013
Actual
Cash
$ in Millions
Dec. 31, 2014
Actual
$3
0%
--
0%
Bank Borrowings
265
12%
197
10%
71/8% Sr Notes due 2017
250
11%
250
13%
87/8% Sr Notes due 2020
222
10%
223
12%
77/8% Sr Notes due 2022
405
19%
405
22%
Net Debt
1,139
52%
1,075
57%
Stockholders’ Equity
1,065
48%
795
43%
$2,204
100%
$1,870
100%
Capitalization
Credit Facility Availability
$185
Credit Statistics
Net Debt/LTM EBITDA
Net Debt/Capitalization
$220
3.0x
51.7%
3.0x
57.5%
All Sr Notes rated B2/CCC+, Corporate Rating B1/B-
21
Debt Maturity Schedule
$450
$400
$350
$300
$250
$200
$150
$100
$50
$0
$400
Senior Notes Maturity Schedule
$250
$225
7.125%
June 1st
2015
2016
2017
7.875%
March 1st
8.875%
Jan 15th
2018
2019
2020
2021
2022
$417.6 Million Bank Borrowing Base
• $220 million in availability as of 12/31/14, matures in November 2017
Bank Covenants Summary(1)
• Current ratio (including undrawn bank line) must be maintained at or above 1.0x
• EBITDA (on a rolling 4 quarter average) to interest expense must be maintained at or
above 2.75 to 1.00 ratio
(1) Please see Exhibit List of December 31, 2014 Form 10-K to obtain references to our Credit Agreement where these covenants
are explained in their entirety.
22
1Q15 & FY15 Production and CapEx Budget(1)
First Quarter 2015
Guidance Range
Total Production Volumes (MMBoe)
2.92 – 2.97
Natural Gas Production (Bcf)
11.1 – 11.2
Crude Oil Production (MMBbl)
0.65 – 0.67
Natural Gas Liquids Production (MMBbl)
0.42 – 0.44
Capital Expenditures (Millions)
$30 – $35
Full Year 2015
Guidance Range
Total Production Volumes (MMBoe)
11.4 – 11.6
Capital Expenditures (Millions)
$110 – $125
(1) Based on Company guidance provided on February 26, 2015 press release.
23
APPENDIX
Fasken Sensitivity Analysis
Model Assumptions
D&C Cost (MM)
EUR (Bcf)
12-15
Lateral Length (ft)
7,500
Proppant (MMlbs)
9-11
IP (MMcf/d)
Mcf/d
$5.5 - $7.0
20
Gas Price (NYMEX)
$2.50 - $4.00
IRR(1)
38% - >100%
24,000
20,000
16,000
12,000
8,000
4,000
0
Enhanced Fasken Well Results(2)
0
30
60
90
120
150
180
Days on Production
210
240
270
300
(1) Model assumptions based on Fasken area wells.
(2) Production occasionally restricted by line pressures, shut ins, operations, and facilities maintenance. For presentations
25
purposes, production history recorded after final production test. Represents wells drilled with enhanced design prior to 1Q14.
AWP Eagle Ford Gas Sensitivity Analysis
Model Assumptions
D&C Cost (MM)
$7.5 - $8.5
EUR (Bcf)
8-10
Lateral Length (ft)
6,500
Proppant (MMlbs)
9-11
IP (MMcf/d)
12,500
Gas Price (NYMEX)
IRR(1)
$2.50 - $4.00
18% - 83%
Enhanced AWP Eagle Ford Gas Type Curve(2)
Mcf/d
12,500
10,000
7,500
5,000
2,500
0
10 Bcf Type Curve
8 Bcf Type Curve
30
60
90
120
150 180 210 240
Days on Production
270
(1) Model assumptions based on AWP EF Gas area wells. Based on fixed WTI price of
$55.00.
(2) For presentations purposes.
300
330
360
26
AWP Eagle Ford Oil Sensitivity Analysis
Model Assumptions
D&C Cost (MM)
$6.0 - $7.0
EUR (MBoe)
400 - 500
Lateral Length (ft)
7,000
Proppant (MMlbs)
9-10
IP (Boe/d)
1,120
IRR(1)
1,250
1,000
750
500
250
0
15% - 39%
Boe/d
Enhanced AWP Eagle Ford Oil Results(2)
0
30
60
90
120
150
180
Days on Production
210
(1) Model assumptions based on PCQ area wells for illustrative purposes.
Based on SFY internal calculations at $55/$3.00.
(2) For presentations purposes .
240
270
300
27
Corporate Information
Corporate Headquarters
Swift Energy Company
16825 Northchase Dr, Suite 400
Houston, Texas 77060
(281) 874-2700 or (800) 777-2412
www.swiftenergy.com
Contact Information
Doug Atkinson, CFA
Manager - Investor Relations
(281) 423-0314
[email protected]
28