SilverBow Resources Corporate Presentation October 2017 Exhibit 99.1

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 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 sbow.com. 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. Future costs may be adversely impacted by increases in oil and gas prices which results in increased activity. THIS PRESENTATION includes information regarding our PV-10 at SEC and strip prices for year end 12/31/16 reserves. PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company’s calculation of PV-10 using strip prices herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes using strip prices as of April 4, 2017, rather than after income taxes using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month. The Company’s calculation of PV-10 using strip prices should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. Please see appendix for a reconciliation of PV-10 to standardized measure as well as a PV-10 value calculated at strip prices as of June 30, 2017. • PAGE •

NYSE Symbol: Market Cap(1): Enterprise Value(1): Strip PV-10 Value(2): 2Q17 Production(3): Production Mix(4): 2016 Proved Reserves: % Proved Developed: Net Acreage SBOW $302 million $506 million $626 million ~146 MMcfe/d 83% Gas 744 Bcfe 52% 76,729 Market capitalization value as of June 30, 2017; EV = Market Cap of $302 million (11.5 million shares @ $26.16/sh) plus $204 million of net debt as of 6/30/17 Year-end 12/31/16 reserves. Monthly NYMEX pricing as of closing on 06/30/2017. See Appendix for pricing. Proved reserves were not changed for the change in pricing. Daily average production presented on a three stream basis Represents reported production mix for 2Q 2017 A Pure Play Eagle Ford Value and Growth Opportunity Company Overview EAGLE FORD FOCUSED Premier Eagle Ford Gas Driller Attractive Core Eagle Ford Position Strengthened Balance Sheet Provides Financial And Operational Flexibility Veteran Management Team With Substantial Experience In The Play • PAGE •

THEN ACTION NOW STATUS Diversified Portfolio Including Conventional Assets Exited Louisiana and Divested Small Non-Core Fields Pure Play Eagle Ford High Cost Rightsizing Initiatives G&A reduced ~55% Operational Cost Structure Initiatives LOE Reduced ~60% Burdensome Midstream Contracts Renegotiated Key Transportation & Processing Agreements MVC’s eliminated Greater ethane flexibility Lower tariffs Stressed Balance Sheet Restructured Debt Simple Capital Structure Reduced P&A Liability ARO reduced ~50% Liquidity & Covenant Constrained $40 million PIPE Refinanced RBL and Upsized Ample liquidity & covenant headroom Limited Hedging Disciplined Strategy Implemented Proactive Hedging Swift Energy Rebranding Initiative SilverBow Resources OTC NYSE Listing NYSE: SBOW Static Eagle Ford Position Strategic Leasing Campaign Growing Eagle Ford Position Ongoing ü SilverBow Resources Transformation ü ü ü ü ü • PAGE • ü ü

EXECUTIVE TEAM YEARS IN INDUSTRY PREVIOUS EXPERIENCE Sean Woolverton – Chief Executive Officer Former COO Samson Resources Former VP at Chesapeake Also held leadership roles at Encana and Burlington 24 Bob Banks – Chief Operating Officer COO since ‘06, joined the Company in ‘04 Previously Santa Fe International and Kuwait Foreign Petroleum 40 Gleeson Van Riet – Chief Financial Officer Former CFO of Sanchez Energy Former investment banker at Credit Suisse and DLJ 25 Chris Abundis – General Counsel GC since ’17, joined the Company in ‘05 Formerly at KPMG 15 Kuwait Foreign Petroleum Strong Leadership Team • PAGE •

2016 Data only complete through November. From IHS on 3/30/2017 Transferring New Completion Technology to Underexploited Areas of the Eagle Ford Underexploited Eagle Ford Gas Fairway • PAGE •

Top Tier Gas Well Performance • PAGE • Source: Drilling Info first 6 month cumulative gas production for Eagle Ford gas wells. Data base includes approx. 2,500 EF gas wells. Performance benchmarks include SilverBow wells. Data as of 3/1/2017. SilverBow Has Drilled 19 of the Top 25 Eagle Ford Gas Wells SilverBow Other Benchmarks

Increasing Demand from Petrochemical Complex, LNG Exports, and Mexico Exports (1) Source: EIA; expected demand growth from 2016 through 2022 Sources of Demand Growth(1) +3-4 Bcf/d +7-10 Bcf/d +3 Bcf/d Best Gas Take-Away Market in the US • PAGE •

Portfolio Overview SilverBow has a superior Eagle Ford acreage position located in parts of the core gas and condensate windows Area Net Acres % Avg Working Interest Drilling Locations(1) % Gas # Producing Wells Fasken Area 6,477 64%-100% Lower Eagle Ford 23 100% 62 Upper Eagle Ford 72 100% 1 AWP Area 31,220 50%-100% AWP South – Gas 78 78% 22 AWP North – Oil 42 20% 74 Artesia Area 9,725 88%-100% Oil / Condensate 39 45% 42 Oro Grande 24,485 100% Lower EF Gas 111 100% 1 Uno Mas 4,822 100% Lower EF Gas 21 100% 0 Other(2) 80 63% 577 Totals 76,729 466 779 Gross locations are on Company operated lease acreage with positive economic returns and classified as proven undeveloped, probable, or possible reserves. Not all acreage may be prospective. Locations are considered Lower Eagle Ford unless notified otherwise. Fasken Olmos, Austin Chalk, and AWP Olmos. Includes ~36 producing horizontal wells in AWP Olmos • PAGE • SBOW Acreage Fasken Artesia AWP Uno Mas Oro Grande

Producing Wells 62 40 1 0 22 1 74 EUR (Bcfe) 14 8.6 14 12 10 10 2.6 Well Cost ($mm) $5.4 $5.5 $8.8 $7.3 $6.9 $5.3 $5.3 Note: 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. Please see type curve analysis for more information. Core Eagle Ford Acreage With Compelling Returns SINGLE WELL IRR BY AREA (FLAT $3.00/$50) Strong Returns Across Portfolio • PAGE •

FASKEN ENHANCED COMPLETIONS IMPROVING EUR BY 133% Pre-2014 Completions Proppant Loading 800 – 1,000 lbs/ft Lateral Length ~5,500 ft Stage Spacing 310 – 520 ft Well Completion Cost ~$4.5 MM 3 Stream EUR 6 – 10 Bcfe 2016 Completions Proppant Loading 1,900 – 2,100 lbs/ft Lateral Length ~7,500 ft Stage Spacing (ft) 230 – 240 ft Well Completion Cost ~$3.2 MM 3 Stream EUR 14+ Bcfe Gen 3 Completion ~3,000 MMCfe Gen 2 Completion ~2,250 MMCfe Gen 1 Completion ~1,750 MMCfe 74% 29% Enhanced Completion Increases Well Productivity • PAGE • Newest Generation of wells exceeding expectations LATEST GENERATION WELL

(e) 64% Decline drilling well cost ($MM)(1)(2) Drilling Cost per foot(1) Completion well cost (no tubing) ($MM) (1) Completion cost per stage (no tubing)($000) (1) Indicative of Fasken well costs; D&C costs are exclusive of location costs and tubing installs. Drilling well cost is rig release to rig release. Represents actuals from pad in late 4Q16 and expected 2017 costs. 67% Decline (e) 42% Decline 49% Decline (e)(2) Culture of Continuous Cost Optimization (e)(3) • PAGE •

Top Quartile on Operating Expenses Note: Total operating expenses include production taxes, gathering and transportation expenses, lease operating expenses, and marketing expense where applicable. Source: Company Filings. Peer group includes, in alphabetical order, Antero, Cabot, Comstock, Eclipse, Gastar, Penn Virginia, Range, Rex, Sanchez, Sandridge, Southwestern. • PAGE • TOTAL OPERATING EXPENSES – 2017 1st QUARTER

Note: By area CAPEX inclusive of all field related costs, including production optimizations, facilities, D&C, etc. Budget subject to adjustments based on changes in commodities and costs. Results in strong production growth of 20% - 25% through the course of 2017 and positions the Company for continued growth in future years 73% D&C Accelerated Capital Budget 2017 Capex: $190 – $200 million 146.5 – 150.5 Mmcfe/d of average production for full year 2017 Oro Grande: 2 wells drilled and 2 completed Uno Mas: 1 well drilled and completed Fasken: 8 wells drilled and 12 completed AWP: 5 wells drilled and completed Artesia: 7 wells drilled and completed • PAGE •

An Opportunity to Replicate Fasken Successes Oro Grande Lower Eagle Ford • PAGE • Fasken Technology Transfer Position was originally built from 3D seismic and a detailed evaluation of offset cores, logs, geo-steering and completion design Analysis confirms a very thick 320’ column of hydrocarbons with free gas in place of ~250 Bcf per 1.5 sections Over-pressured shale (>0.85 psi/ft) at 12,000-13,000 tvd yields higher production rates and gas recovery factor Ability to apply enhanced completion technology to organically grow inventory Drilled first well, NMC#1, with a 7,500’ lateral, 37 frac stages and ~26 MM pounds of placed proppant (3,400 lbs/ft) Reservoir pressure management program is being utilized to minimize pressure drawdown and maintain far field fracture connectivity Current production is ~11 Mmcf/d with ~6,000 PSI of flowing tubing pressure Well has produced 941 Mcf over the first 90 days of production NMC#2 delineation well was drilled to a 7,500’ lateral TD Completion is currently pending Well is approximately 2 miles to the east of NMC#1 and over 99% of lateral is deemed to be within the pre-defined target window Oro Grande Acreage Map Legend: SilverBow Leasehold Area Eagle Ford Trend Black Oil Volatile Oil Condensate Wet Gas Gas Oro Grande Net acres 24,485 Average W.I. (%) 100% Gross Locations 104 (100% LEF) Oro Grande

• PAGE • Oro Grande Tracking Towards Fasken Performance 30 Day Gas Cum (Mmcf)(1) 90 Day Gas Cum (Mmcf) (1) Cumulative Production Comparison Production Rate vs. Time Flowing Tubing Pressure at 90 Days NMC 1-H produced 941 Mmcf in first 90 days Current production of approximately 11 Mmcf/d Initial flowing pressure greater than 8,000 psi Key Takeaways Gas Rate (Mscfpd) PSI Cumulative Production and Strong Pressure Support 14 Bcf Type Curve

• PAGE • Fasken Upper Eagle Ford Performance Fasken State 63H vs. 4-well pad Fasken State 63H UEF/LEF Hybrid 16.1 BCFE EUR Flowback Gas rate production Pressure Hybrid well with lateral 25% in Upper EF and 75% in Lower EF Rate, pressure, cum indicate 63H performs at same level as offset Lower EF wells on the same pad Tracers confirm equal contribution throughout the lateral from both Lower EF and Upper EF After 6 mos. of production on track for a 16.1 Bcfe EUR Fasken State 63H Performance Fasken State 106H vs. Type Curves Rate vs. Time (psi) (Mscfpd) 20-30% uplift expected with Scale Inhibitor and increased lateral length Fasken State 106H No Scale Inhibitor 9.5 BCFE EUR at 7,034’ CLAT (20% improvement = 11.4 BCFE) Tubing Install Fasken State 106H Performance: First Upper EF well with 7,000 ft lateral and 2,000 lbs/ft completion Microseismic indicated frac connection with LEF Projected EUR of 9.5 Bcfe No scale inhibitor used which could further enhance EUR by 20-30% Partial Upper EF Landing First Upper EF well Fasken Upper Eagle Ford Delineation Progressing as Planned with Positive Early Results

$250MM Conforming ~$172MM Outstanding NYSE Symbol Share Price(1) Shares Outstanding(1) Equity Market Capitalization Plus: Debt(1) Less: Cash(1) Enterprise Value SBOW $26.16 11.526 $ 301.5 211.0 6.6 $ 505.9 As of 6/30/17 Note: All values in millions, except per share value amounts KEY HIGHLIGHTS Credit facility only debt $600 million commitment $330 million borrowing base Pricing at L + 275-375bps April 2022 maturity Next redetermination in Fall 2017 Syndicate of 12 banks led by JP Morgan Intend to fund the 2017 capital program with cash flow from operations and borrowings under the credit facility Ability to finance attractive growth opportunities or acceleration • PAGE • Financial Overview

Hedging Position(1) • PAGE • SilverBow actively hedges expected to protect project returns and support planned capital expenditures Bias towards swaps and collars Second Half 2017 weighted average natural gas and crude oil hedges of ~$3.06 and ~$48.17, respectively(2) 2018 weighted average natural gas and crude oil hedges of ~$3.05 and ~$50.96, respectively(2) Hedge volumes for balance of 2017 cover ~65% of 2017 production guidance midpoint Natural Gas Hedging Oil Hedging Note 1: Hedge information is as of 7/21/2017. For more detailed hedging information, please see the Company’s most recent Quarterly report. The above analysis assumes 1 Mcf equals 1 MMBtu. Note 2: Weighted average prices calculated using floor of collars

Why Invest in SilverBow Resources? Value and Growth Investment Opportunity Pure Play Eagle Ford Operator with Premier Record of Drilling Gas Wells Best Gas Take-Away Market in USA Restructured Balance Sheet, Cost Structure, and Midstream Contracts Positions as Low Cost Operator / Consolidator 73% of 2017 Capital Expenditures spent on Drilling and Completions Currently Trading at Attractive Valuation Relative to Strip PV10 with Further Upside From: Capital Constrained PUDs Oro Grande – recently completed first well Uno Mas – drilling first well in 4Q17 Organic Leasing Opportunities Accretive Acquisition Opportunities • PAGE •

Compelling Potential Valuation Capital Constrained PUDs Oro Grande Uno Mas Probable Reserves Note: Year-end 12/31/16 reserves. Monthly NYMEX pricing as of closing on 06/30/2017. See Appendix for pricing. Proved reserves were not changed for the change in pricing. Leasing Acquisitions • PAGE • Value and Growth Investment Opportunity $442 $184 SEC PV10 Strip PV10 Current Enterprise Value: $506 million

Financial Summary • PAGE •

Financial Strategy Preserve Financial Flexibility Maintain Strong Liquidity Position Refinanced RBL with New Syndicate of Lenders Conservative Target Leverage Persistent Focus on Driving Down Costs Continually Hedge to Protect Cash Flows Relaunch Equity Research Coverage • PAGE •

Borrower SilverBow Resources, Inc. Guarantors All existing or future direct or indirect wholly-owned U.S. subsidiaries of the Borrower Facility $330 million Borrowing Base Maturity April 2022 Interest Libor +275-375 bp Syndicate 12 Member Bank Group Redeterminations Semi-annually with next redetermination scheduled Fall 2017 Security First priority liens covering at least 85% of the PV-9 of proved oil and gas reserves; title requirement 85% of the PV-9 Financial Maintenance Covenants Leverage Ratio ≤4.0x Current Ratio ≥1.0x ~$211 million drawn as of 6/30/17 • PAGE • Summary Terms: Revolving Credit Facility

  ACTUAL GUIDANCE   1Q17 2Q17 3Q17 FY17 Production Volumes:       Oil (bbls/d) 1,624 1,532 1,735– 1,800 1,750 – 1,820 NGL (bbls/d) 2,267 2,505 2,655 – 2,750 2,640 – 2,740 Gas (MMcf/d) 112.3 121.7 123 – 125 120 – 123 Total Production (MMcfe/d) 135.6 146.0 149 – 152 146.5 – 150.5     Product Pricing:   Natural Gas NYMEX Differential (per Mcf) $(0.25) $(0.02) ($0.03 - $0.08) N/A Crude Oil NYMEX Differential (per Bbl) $(2.66) $(1.47) ($1.50 - $2.50) N/A Natural Gas Liquids (% of WTI) 41% 38% 36% - 38% N/A   Costs and Expenses   Lease Operating ($/Mcfe) $0.47 $0.36 $0.47 - $0.48 $0.43 - $0.46 Transportation and Production ($/Mcfe) $0.36 $0.36 $0.35 – $0.37 $0.34 - $0.36 Production Taxes (% of Oil and Gas Revenues) 3.8% 5.0% 4.5% - 5% 4.5% - 5% G&A Expenses (Cash Only, $MM) $8.3 $5.2 $4.8 - $5.2 $22.0 – $24.0 DD&A Expense ($/Mcfe) $0.80 $0.82 $0.80 - $0.85 $0.82 - $0.87 Interest Expense ($MM) $3.6 $2.2 $3.0 N/A Guidance • PAGE •

Appendix • PAGE •

South Texas Lease operating costs ($/Mcfe) Net General & administrative, Cash ($MM) South Texas Transportation & processing ($/McfE) Note: 2017 estimates based off of guidance given 5/2/2017 Corporate total recordable incident rate $0.34 - $0.36 $0.43 - $0.46 • PAGE • Maintaining Safety While Driving Down Costs $22.0 - $24.0

BOARD OF DIRECTORS YEARS IN INDUSTRY PREVIOUS EXPERIENCE Marc Rowland – Chairman, Nominating & Strategy Committee Founder and Senior Managing Director of IOG Capital, LP Former CEO of FTS Intl. Former EVP and CFO of Chesapeake >40 Michael Duginski – Audit, Nominating & Strategy Committee President and CEO of Sentinel Peak Resources Former COO of Berry Petroleum 29 Gabriel Ellisor – Audit & Compensation Committee Former CFO at Three Rivers Operating Company Served as principal at Rivington 19 David Geenberg - Nominating & Strategy Committee Co-Head of N.A. investment team at Strategic Value Partners Previously at Goldman, Sachs & Co. 12 Christoph Majeske - Compensation Committee Director of Strategic Value Partners Former VP and Operating Executive at Cerberus 17 Charles Wampler - Audit & Compensation Committee CEO of Resource Rock Exploration Former COO of both Aspect Holdings and Lewis Energy 39 Highly Experienced Board of Directors • PAGE •

PROVED RESERVES GROWTH PV-10 is a non-GAAP measure reconciled to GAAP Standardized measure in the Appendix of the presentation. Net of $33.1 million in ARO. Year-end 12/31/16 reserves. Monthly NYMEX pricing as of closing on 06/30/2017. See Appendix for pricing. Proved reserves were not changed for the change in pricing. 2016 YEAR-END RESERVES COMPOSITION AND LOCATION +76% PDP PDNP PUD 422 Bcfe 744 Bcfe $2.61 $2.43 Natural Gas Price Proved Reserves Growth 2016 YEAR-END RESERVES HIGHLIGHTS Reserve volumes increased 76% year-over-year despite drop in SEC pricing 2015 Bankruptcy filing triggered elimination of most PUDs due to inability to demonstrate capital funding Bankruptcy Exit Plan contained capital to fund development of 44 locations, which were reclassified as PUDs Reserve auditor HJ Gruy has identified an additional 91 locations which would meet qualifications of PUDs if capital was available PV-10 value with SEC pricing of $442 million(1) PV-10 value with strip pricing of $626 million, with 51% of total PV-10 value provided by PDP reserves(2) 94% of reserves are based in Eagle Ford • PAGE •

Net Income for 2Q16 is non-GAAP as it combined 4/1-4/22 and 4/23-6/30 which are two separate reporting periods due to emergence from bankruptcy and implementation of Fresh Start Accounting ($ thousands)  2016 2017   Q2(1) Q3 Q4 Q1 Q2         Net Income $ 810,312 $ 394 $ (7,081) $ 17,710 $ 16,241         Adjustments to EBITDA       DD&A 16,528 13,287 9,815 9,715 10,828 Accretion of ARO 1,151 1,099 947 564 576 Interest, net 9,538 5,880 5,173 3,607 4,642 Impairments 133,496 -- -- -- -- Reorganization items (966,295) 1,193 170 -- -- Derivative (gain) / loss 9,912 (2,603) 12,368 (10,936) (5,132) Derivative cash settlements -- (957) (1,173) (668) (1,621) Non-cash Equity Compensation 338 2,942 486 1,503 1,632         Adjusted EBITDA $ 14,980 $ 21,235 $ 20,706 $ 21,495 $ 27,166 • PAGE • Adjusted EBITDA Reconciliation

Estimates of future net revenues from our proved reserves, Standardized Measure and PV-10 (PV-10 is a non-GAAP measure defined below), as of December 31, 2016 is made in accordance with SEC criteria, which is based on the preceding 12-months' average adjusted price after differentials based on closing prices on the first business day of each month, excluding the effects of hedging and are held constant, for that year's reserves calculation, throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use of fixed and determinable contractual price escalations. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following table. The following prices are used to estimate our SEC proved reserve volumes, year-end Standardized Measure and PV-10. The 12-month 2016 average adjusted prices after differentials were $2.43 per Mcf of natural gas, $41.07 per barrel of oil, and $16.13 per barrel of NGL. As noted above, PV-10 Value is a non-GAAP measure. The most directly comparable GAAP measure to the PV-10 Value is the Standardized Measure. We believe the PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the value of proved reserves on a comparative basis across companies or specific properties without regard to the owner's income tax position. We use the PV-10 Value for comparison against our debt balances, to evaluate properties that are bought and sold and to assess the potential return on investment in our oil and gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our proved oil and natural. The following table provides a reconciliation between the Standardized Measure and PV-10 Value of the Company's proved reserves: (in millions, as of December 31, 2016) 2016 Standardized Measure of Discounted Future Net Cash Flows $ 407 Future income taxes (discounted at 10%) 35 SEC PV-10 Value $ 442 • PAGE • Reconciliation of PV-10 to Standardized Measure PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company’s calculation of PV-10 using strip prices herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes using strip prices as of April 4, 2017, rather than after income taxes using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month. The Company’s calculation of PV-10 using strip prices should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. Note: Strip pricing as of 6/30/2017 shown as Natural Gas / Oil per year: remaining 2017 $3.11 / $46.91 | 2018 $3.00 / $48.51 | 2019 $2.85 / $48.74 | 2020 $2.83 / $50.83 | 2021 $2.86 / $52.09

Type Curves • PAGE •

Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (Bcfe) % Gas EUR / 1,000’ (Bcfe) Type Curve Restricted Rate (MMcfd/1000’) Flat Period (Days) 30 Day IP (MMcfe/d) Initial Decline Following Flat Period B-Factor Terminal Decline 23 $5.4 $5.8 139% 7,500 1,500 14 100% 1.9 2.0 60 15 68% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 0/16/0 201% 339% 0/14/0 139% 230% 0/12/0 92% 149% Type Curve(1) Fasken Lower Eagle Ford Gas • PAGE • 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. Restricted Rate

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (Bcfe) % Gas EUR / 1,000’ (Bcfe) Type Curve Restricted Rate (MMcfd/1000’) Flat Period (Days) 30 Day IP (MMcfe/d) Initial Decline Following Flat Period B-Factor Terminal Decline 72 $5.4 $2.2 31% 7,500 1,500 10 100% 1.3 1.3 30 10 74% 1.7 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 0/11.5/0 43% 67% 0/10/0 31% 48% 0/8.5/0 22% 33% Fasken Upper Eagle Ford Gas • PAGE • 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. Restricted Rate

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (Bcfe) % Gas Gas Shrinkage NGL Yield (bbl/MMcf) EUR / 1,000’ (Bcfe) Type Curve Restricted Rate (MMcfd/1000’) Flat Period (Days) 30 Day IP (MMcfe/d) Initial Decline Following Flat Period B-Factor Terminal Decline 78 $6.9 $5.7 43% 7,500 1,400 10 100% 10% 36 1.3 1.2 0 8.4 61% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 0/11.5/0 60% 88% 0/10/0 43% 63% 0/8.5/0 28% 41% AWP South Eagle Ford Gas Mcfe/d • PAGE • 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.

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (MBOE) % Gas % Oil % NGL EUR / 1,000’ (MBOE) Type Curve Restricted Rate (BOEPD/1000’) Flat Period (Days) 30 Day IP (BOEPD) Initial Decline Following Flat Period B-Factor Terminal Decline 42 $5.3 $2.1 30% 6,300 1,500 430 12% 77% 11% 68 96 60 605 78% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 379/0.63/57 45% 81% 330/0.55/50 30% 54% 280/0.47/42 18% 33% AWP North Eagle Ford Oil • PAGE • 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. Restricted Rate

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (MBOE) % Gas % Oil % NGL EUR / 1,000’ (MBO) Type Curve Restricted Rate (BOEPD/1000’) Flat Period (Days) 30 Day IP (BOEPD) Initial Decline Following Flat Period B-Factor Terminal Decline 39 $5.5 $7.8 81% 7,000 1,500 1,427 45% 23% 32% 204 139 60 972 61% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 375/5.76/353 110% 171% 326/5.01/465 81% 124% 277/4.26/395 56% 86% 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. Artesia Eagle Ford Oil • PAGE • Restricted Rate

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (Bcfe) % Gas EUR / 1,000’ (Bcfe) Type Curve Restricted Rate (MMcfd/1000’) Flat Period (Days) 30 Day IP (MMcfe/d) Initial Decline Following Flat Period B-Factor Terminal Decline 111 $8.8 $4.0 48% 7,500 3,500 14 100% 1.9 1.7 60 13.0 68% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 0/16/0 72% 112% 0/14/0 48% 74% 0/12/0 31% 49% Oro Grande Eagle Ford Gas Mcf/D • PAGE • 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. Restricted Rate

Type Curve(1) Single Well Economics Summary Drilling Locations(1) Target D&C ($mm) NPV 10 ($mm) IRR (%) Type Well Assumptions Completed Lateral Length (ft) Proppant (lbs/ft) Wellhead EUR (Bcfe) % Gas Gas Shrinkage NGL Yield (bbl/MMcf) EUR / 1,000’ (Bcfe) Type Curve Restricted Rate (MMcfd/1000’) Flat Period (Days) 30 Day IP (MMcfe/d) Initial Decline Following Flat Period B-Factor Terminal Decline 21 $7.3 $4.9 47% 7,000 1,500 12 100% 8% 10 1.7 1.8 60 13.0 68% 1.2 5% IRR Sensitivity Gas/WTI/NGL Price $3.00 / $50 / $20 $3.50 / $60 / $24 T.C. EUR Mbo/Bcf/Mbn 0/14/0 71% 113% 0/12/0 47% 75% 0/10/0 27% 45% Uno Mas Eagle Ford Gas • PAGE • 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. Restricted Rate

Corporate Information CORPORATE HEADQUARTERS SilverBow Resources, Inc. 575 North Dairy Ashford, Suite 1200 Houston, Texas 77079 (281) 874-2700 or (800) 777-2412 www.sbow.com CONTACT INFORMATION Doug Atkinson, CFA Senior Manager – Finance & Investor Relations (281) 423-0314 doug.atkinson@sbow.com • PAGE •