Corporate Presentation Swift Energy Company January 2017

Transcription

1 Corporate Presentation Swift Energy Company January 2017

2 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 EURs, 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 forwardlooking 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 Cautionary Note Regarding Potential Reserves Disclosures Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose proved reserves, and optionally 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. This presentation has been prepared by the Company and includes market data and other statistical information from sources believed by it to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on the Company s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although the Company believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. This presentation includes information regarding our current drilling and completion costs and historical cost reductions. Investors should not expect further reduction in such costs of the magnitude experienced since Future costs may be adversely impacted by increases in oil and gas prices which results in increased activity. 2

3 Investment Highlights Attractive Core Eagle Ford Position ~65,000 net acres in the heart of the natural gas and condensate windows of the Eagle Ford Stacked pay opportunity to exploit both Lower and Upper Eagle Ford targets, Olmos, and Austin Chalk Outstanding resource inventory with over 400 identified locations and favorable economics South Texas / Gulf Coast gas has material pricing and cost advantage over NE sources Gulf Coast LNG exports and exports to Mexico projected to make up significant portion of demand growth 2017 capital program focused on core Eagle Ford development Experienced Operator Focused On Execution And Asset Optimization Strengthened Balance Sheet Provides Financial And Operational Flexibility Veteran Management Team With Substantial Experience In The Play Swift has drilled 12 of the top 15 best Eagle Ford gas wells ever drilled (1) Precision targeting and completion innovations are driving enhanced returns Longer laterals and increased proppant utilization have more than doubled EURs Core Fasken single well returns ~150% at $3.00/Mmbtu and current cost structure Acute focus on cost reduction Drilling and completion costs down ~50% from 2014 levels (2) Estimated reduction in corporate G&A (3) and LOE of ~50% since 2015 Over $900mm of unsecured notes and general unsecured claims converted to equity New $320mm credit facility with approximately $160mm of liquidity (4) Proactively managing risk with >70% of estimated 2017 natural gas and crude oil volumes hedged at ~$3.10 and ~$48.10, respectively Non-core asset sales in 2016 provided ~$100MM of proceeds and eliminated ~$50MM of ARO (PV) Experienced management team with over 30 years experience in the sector on average Drilled hundreds of wells in the Eagle Ford and operated in South Texas since 1989 when the Company obtained majority interests in wells producing from the Olmos sand in McMullen county (1) Source: Drilling Info first 6 month cumulative gas production for Eagle Ford gas wells. Data base includes approx. 2,500 EF gas wells. (2) Based on drilling cost per foot and completion cost per stage. (3) G&A reduction includes recently announced January 2017 Reduction in Force (RIF) of ~45% of Corporate Headquarter employees, which results in a 1Q17 charge of ~$2.25 million in severance costs and ~$1 million in non-cash acceleration of incentive equity. (4) Pro-forma for the equity offering which priced on 1/23/

4 Recent Events December 31 Filed for Chapter 11 Restructuring April 22 August 8 F100 period First 100 Days August 9 CEO, CFO announce retirement October 3 Swift Energy Approved to Trade on OTCQX December 1 Lake Washington Transaction for ~$40MM January 23 Priced $40MM Private Placement April 22 Emerged from Chapter 11 Restructuring Newly Constituted Board of Directors 75% Central Louisiana Transaction for ~$48MM October 7 Bob Banks Appointed Interim CEO September 27 Marc Rowland Appointed Chairman of the Board December 8 Remaining 25% Central Louisiana Transaction for ~$8MM January 23 Office Move to Energy Corridor 4

5 South Texas Portfolio Swift has a superior Eagle Ford acreage position located in parts of the core gas window Area County Gross Acres Locations 12/31/16 % Gas Fasken Area Webb 8,122 Lower Eagle Ford % Upper Eagle Ford % Austin Chalk % Olmos % AWP Area McMullen Gas Acreage 6,742 Lower Eagle Ford 18 80% Olmos 2 75% Condensate Acreage 1,960 Lower Eagle Ford 3 60% Oil Acreage 12,700 Lower Eagle Ford 54 20% Artesia Area La Salle Lower EF Oil 4, % Lower EF Cond. 2, % Oro Grande (2) La Salle/McMullen Lower EF Gas 24, % Uno Mas (2) Live Oak Lower EF Gas 3, % Totals 64, SFY Acreage (1) Location methodology: it must be within the Company s operated secured lease acreage, must be within the Company s confirmed favorably risked acreage, must be qualified as proven undeveloped, probable, or possible reserves, and must be spaced for optimum reservoir recovery efficiency. Not all acreage may be prospective. (2) There is currently no production from the Oro Grande and Uno Mas fields. 5

6 Asset Returns by Area (1) SINGLE WELL IRR BY AREA (FLAT $3.00/$50.00) 150% 58% 56% 49% Fasken Oro Grande Gas Uno Mas Gas AWP Eagle Ford Core Eagle Ford Acreage With Compelling Returns (1) Model assumes current drill and complete, transportation and processing, and royalty cost structure. Returns reflect midpoint of given ranges. Please see field specific analysis later in presentation for more details. The Company plans to drill its first well in Oro Grande in 2Q17. The Company has not drilled a well in Uno Mas. Please see type curve analysis for more information. 6

7 Top 50 EF Wells by Six Month Gas Production First Six-Months Cumulative Gas Production (MCF) 2,500,000 2,000,000 1,500,000 1,000, ,000 Top 50 Wells Average Top 10% Average Top Quartile Average 2nd Quartile Average 3rd Quartile Average Swift Other Benchmarks 0 Performance Benchmarks(1) Swift Has Drilled 12 of The Top 15 EF Gas Wells Ever Drilled Source: Drilling Info first 6 month cumulative gas production for Eagle Ford gas wells. Data base includes approx. 2,500 EF gas wells. (1) Performance benchmarks include Swift wells. Data as of 11/1/

8 Importance of Geo-Steering & Longer Laterals (1) 150 Fasken State 92H Well Drilling Path Lateral Length (ft) Stages 92H Out of zone 4, H In zone 7, Fasken State 26H Cumulative Gas Production (Bscf) Legend FASKEN STATE 26H FASKEN STATE 92H Normalized Flowing Time (month) Geo-steering, Longer Laterals = Higher 1 st Year Cum Production (1) Graphics are for presentation purposes only and do not depict all relevant geologic and engineering information. The Fasken State 92H was drilled in 2011 while the Fasken State 26H was

9 Importance of Longer Laterals and Increased Proppant Estimated Ultimate Recovery (MMscf) Estimated Ultimate Recovery (MMscf) 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, ,000 10,000 8,000 6,000 4,000 2,000 Fasken Area: Estimated Ultimate Recoveries (EURs) (1) in Millions of Standard Cubic Feet (MMcf) Compared with Completed Lateral Length (CLAT) * Proppant (in Feet * Million Pounds) Older Wells Newer Wells R² = ,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 AWP Bracken JV: Estimated Ultimate Recoveries (EURs) in Millions of Standard Cubic Feet (MMcf) Compared with Completed Lateral Length * Proppant (in Feet * Million Pounds) Older Wells R² = Completed Lateral Length * Proppant (Feet * Million Pounds) Newer Wells ,000 20,000 30,000 40,000 50,000 60,000 Completed Lateral Length * Proppant (Feet * Million Pounds) Increased Proppant w/longer Laterals Driving Higher EURs (1) Please see EUR disclosure in the Forward Looking Statements 9

10 Acute Focus on D&C Cost Reductions (1) DRILLING WELL COST ($MM) (2) DRILLING COST PER FOOT $5.0 $ $350 $ $4.0 $3.5 $3.0 $2.5 $2.0 $ $250 $200 $150 $100 $ $ (e) $ (e) COMPLETION WELL COST (NO TUBING) ($MM) COMPLETION COST PER STAGE (NO TUBING)($000) $5.0 $4.5 $4.0 $3.5 $3.0 $ $250 $200 $150 $100 $221 $203 $137 $102 $104 $2.0 $1.5 $50 $ Q (e) (3) $ Q (2) (e) (1) Indicative of Fasken well costs; D&C costs are exclusive of location costs and tubing installs. (2) Drilling well cost is rig release to rig release. (3) Represents actuals from pad in late 4Q16 and expected 2017 costs. 10

11 Breakdown of Drilling Cost Reductions at Fasken 3,300 3, ,900 2,700 Cost (M) 2,500 2, ,100 1,900 1, , Well Cost Cost Reductions Design Impact Performance 2015 Well Cost Cost Reductions Design Impact Performance 2016 Well Cost Performance & Design Driving Sustainable Cost Reductions 11

12 Improving Cost Structure and Safety Metrics (1) CORPORATE TOTAL RECORDABLE INCIDENT RATE SOUTH TEXAS LEASE OPERATING COSTS ($/MCFE) $1.00 $0.90 $0.96 $ $ $0.70 $0.60 $0.50 $0.67 $0.53 $0.55-$0.57 $ $ (e) 2017 (e) SOUTH TEXAS TRANSPORTATION & PROCESSING ($/MCFE) GENERAL & ADMINISTRATIVE, NET ($/MCFE) $0.42 $0.40 $0.38 $0.36 $0.34 $0.32 $0.40 $0.34 $0.36 $0.37 $0.36-$0.38 $0.75 $0.70 $0.65 $0.60 $0.55 $0.50 $0.45 $0.40 $0.35 $0.68 $0.58 $0.64 $0.58 $0.41-$0.43 $ (e) 2017 (e) $ (e) 2017 (e) (1) 2016 estimated numbers as of 12/31/ estimates based off of guidance given 1/23/

13 Strategic Objectives for 2017 Refinance RBL with more favorable terms Become the low cost gas producer through technology and efficiency gains Use proceeds from non-core divestitures to high-grade portfolio and position Company for growth Continue to divest of marginal assets to improve operating metrics Delineate Oro Grande Evaluate and high-grade potential additional acreage positions along the Eagle Ford play fairway 13

14 Credit Facility 10 Member bank group $350 $320MM Credit Facility $250MM Conforming $70MM Non-Conforming $300 $250 Liquidity ~$160MM (1) $70MM Non-Conforming 700bp + Libor while non-conforming tranche $25MM 600bp + Libor if non-conforming tranche is < $25MM $200 $150 $100 ~$160MM Outstanding (1) $250MM Conforming bp + Libor (based on utilization) when non-conforming tranche is eliminated $50 $0 Emergence RBL Refinancing The RBL An Early 2017 Priority (1) Pro-forma for the equity offering which priced on 1/23/2017. Assumes equity offering proceeds go toward paying down credit facility borrowings. 14

15 Capital Budget and Production (1) Artesia <1% Maintenance 4% LA 6% 2016 (2) CAPEX by Area ~$70MM Production: Bcfe Cap G&A 13% Fasken - 54% Activity Drill: 7 Complete: 11 AWP - 22% Activity Complete: 4 Production: Bcfe Discretionary 10% Maintenance 2% Cap G&A 6% Artesia <1% Oro Grande 13% Activity D&C: (2) CAPEX by Area ~$85-95MM Fasken - 36% Activity Drill: 5 Complete: 9 AWP - 33% Activity Drill: 2 Complete: 2 (1) By area capex inclusive of all field related costs, including production optimizations, facilities, D&C, land, etc. (2) Estimated 2016 numbers as of 12/31/ guidance as of 1/23/2017 press release. Budget subject to adjustments based on changes in commodities and costs. 15

16 Hedging Position (1) Swift continues to actively hedge expected production to provide predictable cash flows while still allowing for flexibility in capturing increases in prices Swift opportunistically layers on hedges to protect project returns and support planned capital expenditures Bias towards swaps and costless collars >70% of estimated 2017 natural gas and crude oil volumes hedged (2) 2017 weighted average natural gas and crude oil hedges of ~$3.10 and ~$48.10, respectively (3) Gas: Q1 Q2 Q3 Q4 1Q Gas Swaps Volume (MMBtu) 6,300,000 5,420,005 5,104,999 3,725,001 4,395,000 Price $3.10 $2.96 $2.98 $2.92 $3.47 Gas Collars Volume (MMBtu) 750,000 2,400,000 2,865,000 3,102,000 Floor Price (put) $3.30 $3.05 $3.05 $3.10 Ceiling Price (call) $3.90 $3.55 $3.59 $3.72 Oil: Q1 Q2 Q3 Q4 Oil Swaps Volume (Bbls) 106,245 97,401 90,000 84,798 Price $48.04 $48.13 $48.16 $48.18 (1) As of 1/20/2017. (2) Per production guidance on 1/23/2017. (3) Using the midpoint of natural gas collars. 16

17 ASSET OVERVIEW

18 Fasken Lower Eagle Ford Gas Fasken Lower Eagle Ford Leasehold Gross Acres: 8,122 Well Spacing: 660 Lower EF Locations at 12/31/2016: 23 Avg Working Interest: 64% Avg Net Revenue Interest: 51% Operational Excellence Increased Fasken per well reserve bookings to 14 Bcf Increased IPs >100% since entry into the play Improved capital efficiencies w/ longer laterals and more sand Drilled longest lateral to date of 8,697 JV with Saka reinforces operational excellence of SFY Expanded firm takeaway capacity to 190 MMcf/d Successful Upper EF test validates ~60 additional locations in the Upper EF which is over 200 thick at Fasken Enhanced Design Results Fasken State 26H: 1 yr Cum Production 3.72 Bcf Fasken State 29H: 1 yr Cum Production 3.60 Bcf Fasken State 16H: 1 yr Cum Production 3.57 Bcf Dimmit Fasken State 14H Avg IP: 20.6 MMcf/d Fasken State 15H Avg IP: 22.5 MMcf/d Fasken State 16H Avg IP: 23.3 MMcf/d Fasken State 91H Avg IP: 8.3 MMcf/d Enhanced Design Original Design Mexico Fasken State 12H Avg IP: 10.4 MMcf/d Webb Fasken State 19H Avg IP: 22.4 MMcf/d La Salle Fasken State 93H Avg IP: 7.6 MMcf/d Fasken State 92H Avg IP: 5.3 MMcf/d Fasken State 6H Avg IP: 11.4 MMcf/d Fasken State 7H Avg IP: 9.1 MMcf/d Fasken State 38H Avg IP: 30.2 MMcf/d Fasken State 37H Avg IP: 25.2 MMcf/d 18

19 Fasken Cumulative Production Cumulative Gas Production (Bscf) GENERATION 3-25 WELLS GENERATION 2-11 WELLS GENERATION 1-15 WELLS FASKEN STATE 44H FASKEN STATE 45H FASKEN STATE 47H FASKEN STATE 48H FASKEN STATE 49H +29% +74% Normalized Flowing Time (month) Enhanced Completions Improving 1-yr Cum Production By 74% 19

20 Fasken Lower Eagle Ford Economics SINGLE WELL ECONOMICS (1) Target D&C Cost (MM) $5.0 - $5.2 Lateral Length (ft) 7,500 Proppant (MMlbs) IP (MMcf/d) 20 Gas Price (NYMEX) $3.00 IRR ~150% Payout (months) 10 NPV 10 (MM) ~$6.0 EUR (Bcf) 14 EXAMPLE OF NEW GENERATION WELL PERFORMANCE (2) MMcfe/d Days on Production (1) Target D&C costs inclusive of location costs and tubing installation. (2) Production plot represents the Fasken State 16H. Production occasionally restricted by line pressures, shut ins, operations, and facilities maintenance. For presentation purposes, production history recorded after final production test. Additional wells will differ. 20

21 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 The Swift/Saka Joint Venture is working very well and serves as a model for other potential joint venture initiatives in the greater Eagle Ford area 1 st Indonesian investment in U.S. Energy Facilitated accelerated development of the Fasken area 21

22 AWP Eagle Ford Gas Overview AWP Eagle Ford Gas Leasehold Gross Acres: 6,742 Well Spacing: 660 Remaining Locations at 12/31/16: 18 Working Interest: 50% - 98% Net Revenue Interest: 38% - 73% Operational Excellence 2016 Improvements: Reduced average Rig on Well from 32 to 29 days Set new internal technical record Spud to TD in 18 days Successfully pumped ~ 2,000 Lbs proppant/clat Ft Recorded highest initial rate wells in Company s history Record Setting Results 2016 Completions: Bracken JV EF 19H: IP 5,347 Boe/d; 26% liquids Bracken JV EF 20H: IP 5,925 Boe/d; 26% liquids Bracken JV EF 23H: IP 5,245 Boe/d; 23% liquids Bracken JV EF 24H: IP 4,771 Boe/d; 26% liquids Bracken JV EF 23H Avg IP: 5,242 Boe/d Bracken JV EF 14H Avg IP: 2,935 Boe/d Bracken JV EF 13H Avg IP: 3,468 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 8H Avg IP: 2,285 Boe/d Original Design Bracken JV EF 24H Avg IP: 4,771 Boe/d Bracken JV EF 20 Avg IP:5,925 Boe/d Anthony JV EF 1H Avg IP: 1,395 Boe/d Enhanced Design 2015 Completions Bracken JV EF 19H Avg IP: 5,347 Boe/d Bracken JV EF 16H Avg IP: 5,222 Boe/d Bracken JV EF 15H Avg IP: 5,345 Boe/d Whitehurst JV EF 1H Avg IP: 1,882 Boe/d Enhanced Design 2016 Completions (1) AWP Lower Eagle Ford Gas locations only. 22

23 AWP Eagle Ford Gas Economic Analysis AWP EAGLE FORD AREA SINGLE WELL GAS ECONOMICS (1) Target D&C Cost (MM) $6.2 Lateral Length (ft) 7,000 Proppant (MMlbs) 12 IP (MMcf/d) 13 Gas Price (NYMEX) $3.00 IRR 49% Payout (months) 23 NPV 10 (MM) $5.8 EUR (Bcf) 10 ENHANCED AWP EAGLE FORD GAS TYPE CURVE (2) Mcfe/d 20,000 16,000 12,000 8,000 4, Days on Production (1) Based on fixed WTI price of $ Assumes 25% royalty rate. (2) Type curves are derived from the actual production of historical, comparably drilled and completed wells (comparables include geology, reservoir, target placement, lateral placement, frac placement, size and success). Type curves are representative of the expected production from location count wells and do not represent a high or low rate/eur for a given area. Type curves are representative of qualified proved undeveloped, probable, or possible reserve categories. 23

24 Oro Grande Overview (1) Oro Grande Eagle Ford Gas Leasehold Gross Acres: 24,485 Well Spacing: 880 Locations at 1/1/2017: 112 Working Interest: 100% Net Revenue Interest: 75% Record Setting Opportunity Offset core data confirmed by seismic shows Lower Eagle Ford pay thickness > 300 and total gas in place of 220 Bcf/section Lease configuration and surface accessibility allow for efficient well placement and optimum CLATs Appraisal well is planned with 50% longer CLAT, 390% more proppant than best early well First well planned for 2Q17 Bracken JV EF 23H Avg IP: 5,242 Boe/d Bracken JV EF 24H Avg IP: 4,771 Boe/d Bracken JV EF 20 Avg IP:5,925 Boe/d Bracken JV EF 19H Avg IP: 5,347 Boe/d ORO GRANDE (1) Map is for illustration purposes. All acreage may not be prospective for Eagle Ford as drilling results delineate the prospect. 24

25 Oro Grande Lower Eagle Ford Gas ORO GRANDE AREA SINGLE WELL ECONOMICS (1) D&C Cost (MM) $7.8 Lateral Length (ft) 7,500 Proppant (MMlbs) 26.2 IR (MMcf/d) Gas Price (NYMEX) $3.00 IRR 40-75% Payout (months) NPV 10 (MM) $ Preliminary Estimated EUR (Bcfe) PRODUCTION TYPE CURVE (2) Mcfe/d 28,000 24,000 20,000 16,000 12,000 8,000 4, Days on Production (1) Assumes 25% royalty rate. (2) Type curves are derived from the actual production of historical offset wells drilled by third parties (evaluation based on geology, reservoir, target placement, lateral placement, frac placement, size and success). Type curves are representative of the expected production from location count wells and do not represent a high or low rate/eur for a given area. Type curves are representative of qualified proved undeveloped, probable, or possible reserve categories. 25

26 Uno Mas Gas Economic Analysis UNO MAS AREA SINGLE WELL GAS ECONOMICS (1) D&C Cost (MM) $6.7 Lateral Length (ft) 7,500 Proppant (MMlbs) 11.3 IP (MMcf/d) 20 Gas Price (NYMEX) $3.00 IRR 48% - 63% Payout (months) NPV 10 (MM) $4.6 - $6.3 Preliminary Estimated EUR (Bcfe) PRODUCTION TYPE CURVE (2) Mcfe/d 20,000 16,000 12,000 8,000 4, Days on Production (1) Assumes 25% royalty rate. (2) Type curves are derived from the actual production of historical offset wells drilled by third parties (evaluation based on geology, reservoir, target placement, lateral placement, frac placement, size and success). Type curves are representative of the expected production from location count wells and do not represent a high or low rate/eur for a given area. Type curves are representative of qualified proved undeveloped, probable, or possible reserve categories. 26

27 APPENDIX

28 Favorably Positioned (1) Gulf Coast Gas Has Material Pricing And Cost Advantage (1) Graphics are for presentation purposes only and do not depict all relevant information. 28

29 Portfolio Management Sharpens Focus on Eagle Ford 2016 Transactions Sold Lake Washington Sold South Bearhead Creek & Burr Ferry Sold Masters Creek and Sun TSH Portfolio Strengthening in Texas Eagle Ford Evaluating high quality Eagle Ford bolt-on / expansion opportunities in the gas and gas condensate windows Evaluating older wells in portfolio to trim the tail Improves operating metrics Eliminates retirement obligations Enhanced Balance Sheet Through ~$100MM of Net Sales Proceeds And The Elimination of $50MM (PV) of ARO 29

30 Competitive & Improving Cost Structure $ rd Qtr - Total Operating Expenses (pre-g/a, $ per Mcfe) $2.50 $2.00 $1.50 Peer Group Avg: $1.57 $1.00 $0.50 $- Peer A Peer B Peer C Peer D Peer E Peer F Peer Group Median Peer G Peer H Peer I Peer J Swift Energy Peer K Peer L Source: Company Filings. Peer group includes, in no particular order, Penn Virginia, Sanchez, Gastar, Comstock, Cabot, Sandridge, Linn, Eclipse, Rex, Antero, Range, and Southwestern 30

31 Corporate Information Corporate Headquarters Swift Energy Company 575 North Dairy Ashford, Suite 1200 Houston, Texas (281) or (800) Contact Information Doug Atkinson, CFA Senior Manager Finance & Investor Relations (281)