INVESTOR PRESENTATION JUNE 19, 2018

INVESTOR PRESENTATION JUNE 19, 2018

Important Disclosures Forward-Looking Statements This presentation contains projections and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Words such as estimate, project, will, may, anticipate, plan, intend, believe, expect, outlook, guidance, target, objective, forecast or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. These projections and statements reflect the Company s current views with respect to future events and financial performance as of this date. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. For a summary of events that may affect the accuracy of these projections and forward-looking statements, see Risk Factors in our Form 10-K for the year ended December 31, 2017 filed with the Securities and Exchange Commission (the SEC ). Unless legally required, Callon does not undertake any obligation to update forward looking statements as a result of new information, future events or otherwise SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES This presentation includes non-gaap measures, such as Adjusted EBITDA, Adjusted Income, Adjusted Income per diluted share, Adjusted G&A and other measures identified as non- GAAP. Adjusted EBITDA is a supplemental non-gaap financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles ( GAAP ). Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. We believe that the non-gaap measure of Adjusted income available to common shareholders ( Adjusted Income ) and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted income per diluted share below were computed in accordance with GAAP. Adjusted general and administrative expense ( Adjusted G&A ) is a supplemental non-gaap financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans. We believe that the non-gaap measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The Appendix table details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A. For a reconciliation of non-gaap measures to their most directly comparable GAAP measure, please see schedules included in the Appendix.

Important Disclosures METRIC CALCULATION METHODOLOGIES $ / Net Acre (Adj.): This calculation aims to normalize transaction purchase prices for the value of the production acquired to arrive at an implied adjusted valuation for the undeveloped acreage acquired. The adjustment value for the acquired production is determined by applying what management believes is a reasonable valuation multiple for the present value of a flowing equivalent barrel of production based on prevailing NYMEX strip pricing at the time of the acquisition to reported sustained production rates at the time of the acquisition. This adjusted undeveloped valuation is then divided by the net surface acreage acquired to yield a best-efforts, apples-to-apples transaction metric to use as a rough guide for relative valuation purposes. $ / Net Delineated Hz Location (Adj.): This calculation aims to normalize transaction purchase prices for the value of the production acquired to arrive at an implied adjusted valuation for the inventory of undeveloped horizontal locations (net to the acquired interest), in zones, which management believes to have been sufficiently delineated by operated and/or offsetting industry activity to date. The adjustment value for the acquired production is determined by applying what management believes is a reasonable valuation multiple for the present value of a flowing equivalent barrel of production based on prevailing NYMEX strip pricing at the time of the acquisition to reported sustained production rates at the time of the acquisition. It also adjusts for management s estimates of value for midstream and water disposal infrastructure and net acreage that does not currently carry delineated well locations. This adjusted undeveloped valuation is then divided by the previously described net identified horizontal locations acquired to yield a best-efforts, apples-to-apples transaction metric to use as a rough guide for relative valuation purposes. 3

Callon Petroleum 1Q18 RESULTS CURRENT RIG ACTIVITY 1Q18 production of 26.6 Mboe/d Oil mix of 77% YOY growth of 30% Operating margin of $44.31 per Boe (~83%) LOE per Boe $5.45 (1) Adjusted EBITDA of $91.7MM OPERATIONAL HIGHLIGHTS Successful early time results from WC A downspacing test in Wildhorse Strong initial production from first Spur two well pad (UWC A & LWC A) 25%+ improvement in Delaware Basin drilling efficiency Drilling of 1 st mega-pad at Monarch underway Pro-forma Key Statistics (2) Shares Outstanding Market Capitalization Net Debt 227 MM $2.3 B $1.0 B Enterprise Value $3.3 B Net debt/1q18 LQA Adj. EBITDA (3) 2.0x 85,000+ PRO FORMA NET ACRES 1. LOE figures are calculated on a two-stream basis 2. Statistical measures for Market Capitalization and Enterprise Value are as of market close on June 14, 2018. Shares outstanding and net debt are represented pro forma for the recently announced Delaware Basin acquisition and related senior notes and equity offerings 3. LTM Adjusted EBITDA calculated as Callon LTM Adjusted EBITDA plus acquisition 1Q18 Adjusted EBITDA annualized. For a reconciliation of Callon s Net Income (Loss) to Adjusted EBITDA see the Offering Memorandum 4

Sustained, Leading Operating Margins OPERATING MARGIN GROWTH ($/Boe) $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 $44.31 $40.51 $34.02 $28.90 $27.83 $30.34 $32.32 $32.58 2Q 2016 3Q 2016 4Q 2016 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 1Q 2018 OPERATING MARGIN PEER COMPARISON ($/Boe) $50 $44.31 $40 $10/Boe $17/Boe $30 Peer Average $34.72 /Boe $20 CPE Peer #1 Peer #2 Peer #3 Peer #4 Peer #5 Peer #6 Peer #7 Peer #8 Peer #9 Note: Peer set includes CDEV, CXO, EGN, FANG, LPI, MTDR, PE, PXD, REN 5

Midland Basin Operational Updates 2 nd QUARTER MIDLAND ACTIVITY SHIFT Monarch recycling program yielding benefits Recent wells have been able to source over 40% of frac volumes from recycling Model for expanded efforts across footprint 2Q18 primary activity areas 1 st mega-pad underway at Monarch Targeting two Lower Spraberry flow units Completion operations recently commenced WildHorse increasing activity during 2Q Positive initial results from WCA down-spacing test Remaining 2018 scheduled activity still set for 660 spacing (monitoring down-spacing test results) Intra-basin sand testing underway with positive early results Multi-well pads in Fairway area driving operational efficiency 6

Day 1 Day 11 Day 21 Day 31 Day 41 Day 51 Day 61 Day 71 Day 81 Day 91 Day 101 Day 111 Day 121 Day 131 Day 141 Day 151 Day 161 Day 171 Day 181 Day 191 Day 201 Day 211 Day 221 Cumulative Oil (Bbl) Wildhorse WC A Down-Spacing Test Early results are very encouraging with ten well spacing test (Open wells) currently exceeding cumulative oil plots for comparable two well pads (eight well spacing) 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 OPEN A2 #1AH OPEN A3 #3AH PLAYERS #1AH PLAYERS #2AH WYNDHAM #1AH WYNDHAM #2AH 7

Cumulative Oil (Bbls) Delaware Basin Ramping Activity SPUR AREA IN PROGRAM DEVELOPMENT MODE Strong initial results from Rendezvous two well pad (Upper and Lower WC A) Rendezvous Pad Improved efficiency in drilling as activity increases Goodnight Midstream pipeline projected online in 3Q, recycling projects moving forward Goodnight Midstream water pipeline Upcoming delineation of Wolfcamp C and 2 nd Bone Spring Shale 70,000 60,000 50,000 40,000 30,000 20,000 10,000 Day 10 Day 20 Day 30 Day 40 - Day 50 Rendezvous Avg Cum Oil Prior 4 Well Avg Cum Oil 8

Improved Delaware Drilling Efficiency AVERAGE DRILLING FOOTAGE PER DAY 18% increase 8% increase 1st 2nd 3rd 4th 5th 6th Offset Operator Callon Operated Delaware Wells Average CPE Average Latest CPE Well Note: Offset Operator average is composed of 14 recent peer results in the southeast Delaware basin targeting the Wolfcamp 9

Delaware Basin Acquisition Overview ASSET HIGHLIGHTS PRO FORMA DELAWARE POSITION (~47,500 NET ACRES) ~29,000 net surface acres that complement existing Spur area position Delineated 3BS, WCA and WCB benches with other emerging upside potential Over 90% HBP Operatorship of 85%+ delineated locations Significant base of high oil-cut (73% oil (1) ), lower decline production Established infrastructure enhances Callon s existing Delaware Basin capacity Key Acquisition Stats Purchase Price $570mm Average Net Daily Production (1) 6,831 Boe/d Total Net Acres Bone Spring 28,657 Wolfcamp 18,925 Net Delineated Hz Locations (2) 212 OPERATED NET LATERAL FEET ON CALLON WITHIN 1-MILE OTHER WC 32% 43% 25% Implied Adjusted Transaction Metrics (3) $ / Net Acre $10,355 $ / Wolfcamp Net Acre $15,680 BS 25% 35% 40% $ / Net Delineated Hz Location (2) $1.4mm 1. Based on average net daily production for the quarter ended March 31, 2018 2. Includes 29 3BS, 129 WCA and 75 WCB only and does not account for emerging upside potential from additional benches 3. Transaction metrics adjusted for production at $40,000 per flowing barrel 10

Building Scale in the Core of the Delaware December 2016 December 2017 May 2018 Loving Winkler Loving Winkler Loving Winkler Ward Ward Ward Reeves Reeves Reeves Callon Dec 2016 Callon May 2018 Callon Dec 2016 Pecos 2017 Bolt-Ons Pecos Acquisition Pecos Acquired Assets from Ameredev ~16,100 Total Net Acres Bolt-On Acreage Acquisitions Pro Forma Delaware Acreage Position ~47,500 Total Net Acres Highly focused additions have enhanced our core operated position 11

Strategic Acquisition Complements Our Strategy Unique Bolt-On Opportunity Bolsters position in oil rich, over-pressured core of Delaware Basin Land / ownership depth synergies unlock significant value Benefits from existing geologic and technical data sets Contiguous Acreage Benefits Increased working interest and extended laterals drive near-term NAV benefits Enhances optionality for multi-well pad development Leverage of existing infrastructure on both footprints Compelling Corporate Value Proposition Near-term corporate returns generated from established production base Accretive to CF per DAS and ROCE Additional organic upside from emerging target zones 1. Acquisition portion of pro forma 1Q18 Adjusted EBITDA is calculated as follows: midpoint of revenue range less midpoint of direct operating expenses range of seller for 1Q 2018 as disclosed in the Offering Memorandum 12

Expansion in the Core of the Delaware Basin CORE ACREAGE POSITION Expands operating position in the core of the Southern Delaware Basin Primary Wolfcamp horizons contain attractive combination of reservoir properties High OOIP High reservoir pressure High % oil WOLFCAMP TOTAL OOIP (MMBO/SEC) Reeves Loving Ward Winkler Pecos High 200 Wolfcamp Total OOIP (Mmbo/sec) 0 Low WOLFCAMP RESERVOIR PRESSURE Loving Reeves Ward Winkler Pecos High 10,000 Wolfcamp Reservoir Pressure (psi) 2,000 Low Comprehensive 3D seismic coverage across pro forma acreage Improves placement of lateral in zone for more effective completions Advantage for delineation of emerging zones WOLFCAMP A & B (% OIL) Loving Winkler Ward High 100% Wolfcamp Percent Oil 0% Low 3D SEISMIC COVERAGE Loving Ward Winkler Core operating area features structurally quiet basin floor with minimal faulting through position Reeves Reeves Pecos 3D Seismic Coverage Pecos 13

Cumulative Oil Production (MBO) Normalized to 7,500 Wolfcamp A Design & Performance Optimization COMPLETION DESIGN EVOLUTION CORBETS 34 149 #02WA SLEEPING INDIAN A1 #01LA SARATOGA A1 #07LA RENDEZVOUS A1 #01LA & #09UA 1 Corbets 34 149 #02WA Prior operator Kitchen Sink Design high proppant/fluid loading and peak cluster/stage density 180 160 140 SELLER WCA AVG (9 wells) 3 1 S 2 Saratoga #07LA Testing lower cost limit 30% lower proppant load, 15% less fluid load, 40% lower stage/cluster density 120 100 2 3 Sleeping Indian #01LA Cost / benefit optimization lower proppant/fluid load offset by 50% increase in cluster density and use of frac tech 80 60 40 4 4 S Rendezvous Pad Multi-well pad application Upper A / Lower A codevelopment Seller WCA Hz PDPs 20 0 0 30 60 90 120 150 180 210 240 270 300 330 360 Days on Production Demonstrated performance improvement through optimized landing zone and completion design 1. All wells normalized to 7,500 lateral length 14

Benefits of Significant Existing Infrastructure FACILITIES HIGHLIGHTS INTEGRATED FACILITIES FOOTPRINT SUPPORTS EFFICIENT PAD DEVELOPMENT Four operated SWD wells with 95 Mbbl/d of current injection capacity Supporting water gathering lines Full electrification across acquired asset base Increased scale enhances recycling initiative benefiting capital and LOE PAD DEVELOPMENT SAVINGS Single Well Pad Integration of acquired infrastructure into combined footprint provides ample capacity to facilitate cost-efficient, multi-well pad development 15

Upside 2 nd Bone Spring Shale & Wolfcamp C A B C D E F Industry delineation continues beyond primary horizons (Wolfcamp A, Wolfcamp B and 3 rd Bone Spring) UL Mayflower 42-18 3H Felix Energy IP24/1,000 : 194 Boe/d Spud Date: 7/6/2017 County Line 18B-C2 1H Jagged Peak IP30/1,000 : 170 Boe/d Spud Date: 9/15/2017 Whiskey River 7374B 1H Jagged Peak IP24/1,000 : 298 Boe/d Spud Date: 9/17/2017 Whiskey River 7374A 1H Jagged Peak IP24/1,000 : 290 Boe/d Spud Date: 9/15/2017 McIntyre State 40 1H Diamondback IP30/1,000 : 85 Boe/d Spud Date: 3/15/2016 County Line 18A-C2 1H Jagged Peak IP30/1,000 : 180 Boe/d Spud Date: 3/25/2017 Estimated 172 total net upside locations targeting the 2BS and WCC 2 nd Bone Spring Wolfcamp C H G 5 2 Loving L 1 Reeves K I A J E 3 C F B Winkler Ward D 4 Pecos G H I J K L Arno 78 121H Matador IP30/1,000 : 144 Boe/d Spud Date: 1/15/2017 Dorothy White 82 124H Matador IP30/1,000 : 140 Boe/d Spud Date: 3/8/2017 UL 20 Sugarloaf 1H Forge/Oasis IP24/1,000 : 112 Boe/d Spud Date: 8/15/2017 Morrison H B 73H Oxy IP24/1,000 : 195 Boe/d Spud Date: 10/17/2016 Shavano 38-28 1H Felix Energy IP30/1,000 : Pending Spud Date: 12/14/2017 Collie A East N 63H Oxy IP30/1,000 : 93 Boe/d Spud Date: 4/26/2017 1 2 3 4 5 Link 1-32 Unit 4H Anadarko IP24/1,000 : 166 Boe/d Spud Date: 3/25/2017 Elmer 33-67 801H Energen IP24/1,000 : 121 Boe/d Spud Date: 3/25/2017 UL Fourmile 1H Felix Energy IP24/1,000 : 160 Boe/d Spud Date: 3/25/2017 State 5913A GGH 2H Jagged Peak IP24/1,000 : 177 Boe/d Spud Date: 3/25/2017 Townsen 66 1 Carrizo IP30/1,000 : 120 Boe/d Spud Date: 2/11/2017 Callon plans to test upside horizons in 2018 (2 nd Bone Spring and Wolfcamp C) 16

% Increase Value Enhancing Financial Impact BENEFICIAL FINANCIAL IMPACTS Transaction is a measured approach to growth that is immediately accretive to debt-adjusted per share metrics, including cash flow and production, and returns on capital employed Material current cash flow contribution from significant PDP base Provides meaningful optionality for planned capital allocation, but limited HBP requirements supports a measured approach to development Accelerates path to free cash flow generation Completed acquisition financing preserves liquidity and maintains strong balance sheet and leverage metrics Pro forma net debt / 1Q 18 annualized Adjusted EBITDA of 2.0x (1) Expected liquidity benefits from planned borrowing base redetermination ACQUISITION DRIVES SIGNIFICANT VALUE ENHANCEMENT 80% +67% 60% +51% 40% 20% +13% +26% 0% Shares Outstanding 1Q'18 Net Production (2) Net Acres Gross Hz Locations Current 26.6 Mboe/d ~56,900 net acres 1,545 gross Hz locations Pro Forma 227.5 MM (3) 33.4 Mboe/d ~86,100 net acres 2,581 gross Hz locations 1. Acquisition portion of pro forma 1Q18 Adjusted EBITDA is calculated as follows: midpoint of revenue range less midpoint of direct operating expenses range and financing transactions 2. Based on average net daily production for the quarter ended March 31, 2018 3. This reflects underwriters exercising shoe in full for the equity issuance closed on May 30th, 2018 17

% of Consensus Oil Financial Positioning HIGHLIGHTS Long-term acquisition financing completed $299MM equity offering $400MM 8NC3 senior unsecured notes Leverage statistics preserved and liquidity position enhanced Borrowing base redetermination to be completed at closing of acquisition RISK MANAGEMENT (3) PRO FORMA CAPITALIZATION ($MM) 1Q18 Adj. Pro Forma Cash $18 37 $55 Credit facility 75 (75) 0 Senior notes due 2024 600 600 New senior notes 0 400 400 Total debt $675 $1,000 Preferred stock 73 73 Stockholders equity 1,838 289 2,127 Total capitalization $2,586 $3,200 Credit statistics Net debt / LTM Adj. EBITDA (1) 2.2x 2.3x Net debt / LQA Adj. EBITDA (2) 1.8x 2.0x 70% Liquidity Commitment amount $650 $650 45% 40% 30% 20% Less: drawn (75) 0 Plus: cash 18 55 Total liquidity $593 $705 2H18 2019 2020 NYMEX WTI Midland-Cushing 1. LTM Adjusted EBITDA calculated as Callon LTM Adjusted EBITDA plus acquisition 1Q18 Adjusted EBITDA annualized. For a reconciliation of Callon s Net Income (Loss) to Adjusted EBITDA see the Appendix 2. Acquisition portion of pro forma 1Q18 Adjusted EBITDA is calculated as follows: midpoint of revenue range less midpoint of direct operating expenses range of seller for 1Q 2018 3. Based off current consensus production estimates per FACTSET as of June 14, 2018 18

Physical Oil Flow Assurance $/Bbl OFFTAKE ~ 90% on pipeline/gathering systems (proforma) with firm transport Long-term firm sales agreements (NYMEXbased) with multiple counterparties with FT out of the Permian Acquired acreage under long-term firm sales agreements Enhanced marketing options with larger proforma production base 55% Current Production 45% Current Production Acquired Production Pipe takeaway Medallion Firm Transport Purchasers Shell, BP, Trafigura, Rio Energy, Delek Enterprise / Plains Firm Sales Enterprise Firm Sales OIL TRANSPORT EVOLUTION ($/Bbl) 1Q18 OIL PRICE REALIZATIONS 2 ($/Bbl) $3.00 $62.50 $62.28 $2.50 $2.00 $62.00 Peer Average: $61.57 $1.50 $1.00 $0.50 $0.00 $61.50 $61.00 $60.50 Trucking On Pipe $60.00 CPE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 1. Hedge contracts as of June 14, 2018 2. Peers included in oil price realization chart : CDEV, CXO, EGN, FANG, JAG, LPI, PE, RSPP 19

Portfolio Approach Provides Broad Optionality Oil Marketing Arrangements Firm Transport on Medallion System Provides Broad Options for Delivery Firm sales volumes are covered by buyer held FT agreements for transport out of the Permian basin Diversified purchaser portfolio (Plains, Enterprise, Shell, BP, Trafigura, Delek, etc.) with multi-year term agreements covering up to 60KBopd More than 90% of oil on pipe (pro-forma) with additional tie-ins pending for Medallion system >60% of CPE (1) oil to flow on Medallion by YE 18 Firm delivery to all market off-take points Capacity increasing with production growth Centurion Basin Centurion PE II WTG Bridgetex Primary transport rights on Medallion equivalent to other preferred shippers Multi-year firm gathering commitments from three primary providers (Enterprise, Plains, Medallion) with ratable increases covered as volumes grow Midland to Sealy Sales are linked to NYMEX based pricing mechanisms Gas Marketing Arrangements Medallion pipeline Medallion offtake points Longhorn Cactus II (Pending) Grey Oak (pending) Multi-year dedications with WTG, Enlink, Targa, and Brazos across the basin Delaware purchaser flows direct connect to El Paso 1600 line with additional capacity pending on Whitewater line Buyer 1 Buyer 2 Buyer 3 Buyer 4 Buyer 5 Buyer 6 Buyer 7 Up to 14 Mbopd Up to 10 Mbopd Up to 10 Mbopd Up to 8 Mbopd Up to 6.7 Mbopd Up to 6 Mbopd Flows on FT Flows on FT Flows on FT Flows on FT Flows on FT Flows on FT Nymex based pricing Nymex based pricing Nymex based pricing Nymex based pricing Nymex based pricing Nymex based pricing Up to 3 Mbopd FT or local refinery sale Nymex based pricing 1) Projected oil volumes are annual exit rate figures for legacy CPE properties 20

Callon Pure Play Peers <$10 Bn Market Cap Cochran Hockley Lubbock Cochran Hockley Lubbock Cochran Hockley Lubbock Cochran Hockley Lubbock Yoakum Terry Lynn Yoakum Terry Lynn Yoakum Terry Lynn Yoakum Terry Lynn Lea Gaines Dawson Borden Lea Gaines Dawson Borden Lea Gaines Dawson Borden Lea Gaines Dawson Borden NM TX Andrews Martin Howard NM TX Andrews Martin Howard NM TX Andrews Martin Howard NM TX Andrews Martin Howard Loving Winkler Ector Midland Glasscock Loving Winkler Ector Midland Glasscock Loving Winkler Ector Midland Glasscock Loving Winkler Ector Midland Glasscock Reeves Ward Crane Upton Reagan Reeves Ward Crane Upton Reagan Ward Reeves Crane Upton Reagan Reeves Ward Crane Upton Reagan Pecos Crockett Pecos Crockett Pecos Crockett Pecos Crockett Brewster Callon May 2018 Acquisition Terrell Val Verde Brewster Jagged Peak Terrell Val Verde Brewster Centennial Terrell Val Verde Brewster RSP Permian Terrell Val Verde Callon 1Q 18 Pro Forma: Net acres: ~86,100 Net Mbo/d: 25.6 Op. margin ($/boe): $43.92 Jagged Peak 1Q 18: Net acres: ~77,700 Net Mbo/d: 21.9 Op. margin ($/boe): $44.90 Centennial 1Q 18: Net acres: ~80,100 Net Mbo/d: 31.6 Op. margin ($/boe): $35.28 RSP Permian 1Q 18: Net acres: ~91,900 Net Mbo/d: 45.3 Op. margin ($/boe): $40.34 Callon has amassed a highly economic acreage position ripe for full-scale development Source: Latest public investor presentations and 10-Q filing for the quarter ended March 31, 2018 Note: Operating Margin defined as unhedged sales revenue less lease operating expenses, gathering and transportation expenses and production taxes 21

APPENDIX

Water Disposal as a Competitive Advantage Between company owned and third party committed volumes, Callon has in excess of 400,000 bbl/d of water disposal capacity (excluding pending Goodnight project of 80,000 bbl/d) Average CPE water disposal during February was ~90K Bwpd across the entire Permian footprint (25% of controlled capacity) COMPANY OWNED AND OPERATED DISPOSAL CAPACITY BY AREA ~50,000 bwpd ~60,000 bwpd WATER MANAGEMENT INITIATIVES Strategic Water Handling Agreements Gravity water sourcing (Wildhorse and Spur areas) Goodnight Midstream Spur disposal pipeline to the CBP Recycling Efforts ~45,000 bwpd Underway at Monarch, utilized on recently fracked wells +40% of sourced volumes Spur build-out progressing, goal of sourcing 50% of frac water volumes from recycling by year end ~100,000 bwpd Incremental Capacity in Key Areas New Deep Ellenburger wells projected online at Ranger and Wildhorse during Q2 supplying significant incremental capacity 23

Current Guidance Summary (Unadjusted for Acquistion) FY18 Guidance Total production (MBoepd) 29.5 32.0 Oil production 77% Income statement expenses (per BOE) LOE, including workovers $5.25 - $6.25 Production taxes, including ad valorem (% of unhedged revenues) 6% Adjusted G&A: cash component (1) $1.75 - $2.50 Adjusted G&A: non-cash component (2) $0.50 - $1.00 Cash interest expense (3) $0.00 Statutory income tax rate 22% Capital expenditures ($MM, accrual basis) Total operational capital (4) $500 - $540 Capitalized expenses $60 - $70 Net operated horizontal wells placed on production 43 46 1. Excludes stock-based compensation and corporate depreciation and amortization. See the Non-GAAP related disclosures in the Appendix 2. Excludes certain non-recurring expenses and non-cash valuation adjustments. See the non-gaap related disclosures in the Appendix 3. All cash interest expense anticipated to be capitalized 4. Includes drilling, completions, facilities, seismic, land and other items. Excludes capitalized expenses. Net of infrastructure monetizations of $20 million 24

Hedge Contracts (1) Crude Oil (MBbl, Wtd Avg. $/Bbl) 2H18 1H19 2H19 1H20 2H20 Swaps Strike Price Costless Collars Short Call Price Put Price Three-way Collars Short Call Price Put Price Short Put Price Deferred Premium Puts Put Price Avg. Premium Midland-Cushing Basis Differential Swap Price 1,104 $52.07 184 $60.50 $50.00 1,748 $60.86 $48.95 $39.21 552 $65.00 $2.26 2,255 ($3.82) - - - - - - - - 1,629 $63.71 $53.89 $43.89 905 $65.00 $6.45 1,991 ($5.75) 1,840 $63.70 $54.00 $44.00 920 $65.00 $6.45 2,024 ($3.63) - - - - 1,820 ($1.69) 1,840 ($1.25) Total NYMEX WTI Hedge Volume Weighted Average Floor Price 3,588 $52.43 2,534 $57.86 2,760 $57.67 - - Natural Gas (BBtu, Wtd. Avg. $/MMBtu) 2H18 Swaps Strike Price 2,760 $2.91 Total NYMEX Henry Hub Hedge Volume Weighted Average Floor Price 2,760 $2.91 1. Hedge contracts as of June 15, 2018. 25

Non-GAAP Reconciliation (1) Adjusted Income Reconciliation 1Q17 2Q17 3Q17 4Q17 1Q18 Income available to common stockholders $ 45,305 $ 31,566 $ 15,257 $ 21,001 $ 53,937 Adjustments: Change in valuation allowance (13,119) (11,194) (6,064) (8,285) (11,753) Net (gain) loss on derivatives, net of settlements (11,566) (6,995) 8,416 16,924 (3,143) Change in the fair value of share-based awards (189) (315) 475 562 799 Settled share-based awards 4,128 Adjusted Income $ 20,431 $ 17,190 $ 18,084 $ 30,202 $ 39,840 Adjusted Income per fully diluted common share $ 0.10 $ 0.09 $ 0.09 $ 0.15 $ 0.20 Adjusted EBITDA Reconciliation Net income $ 47,129 $ 33,390 $ 17,081 $ 22,824 $ 55,761 Adjustments: Net (gain) loss on derivatives, net of settlements (17,794) (10,761) 12,947 26,037 (3,978) Non-cash stock-based compensation expense 639 499 1,952 2,101 2,143 Settled share-based awards 6,351 Acquisition expense 450 2,373 205 (112) 548 Income tax expense 466 322 237 248 495 Interest expense 665 589 444 461 460 Depreciation, depletion and amortization 24,932 26,765 29,132 37,222 36,066 Accretion expense 184 208 131 154 218 Adjusted EBITDA $ 56,671 $ 59,736 $ 62,129 $ 88,935 $ 91,713 (2) Adjusted EBITDA inclusive of Pro forma Adjustments $ 59,329 $ 59,736 $ 62,129 $ 88,935 $ 91,713 1. See Important Disclosure slides for disclosures related to Supplemental Non-GAAP Financial Measures 2. Adjusted EBITDA inclusive of Pro forma Adjustments is used primarily for the purpose of calculating compliance with covenants, such as Debt/EBITDA calculations, and includes the impact of acquisitions closed during prior periods as if they were completed at the beginning of the reporting period 26

Non-GAAP Reconciliation (1) Adjusted G&A Reconciliation 1Q17 2Q17 3Q17 4Q17 1Q18 Total G&A expense $ 5,206 $ 6,430 $ 7,259 $ 8,173 $ 8,769 Adjustments: Less: Early retirement expenses (444) Less: Early retirement expenses related to share-based compensation (81) Less: Change in the fair value of liability share-based awards (non-cash) (307) 567 (731) (844) (991) Adjusted G&A total 5,513 6,472 6,528 7,329 7,778 Less: Restricted stock share-based compensation (non-cash) (921) (966) (1,198) (1,202) (1,105) Less: Corporate depreciation & amortization (non-cash) (121) (114) (146) (125) (124) Adjusted G&A cash component $ 4,471 $ 5,392 $ 5,184 $ 6,002 $ 6,549 Adjusted Total Revenue Reconciliation Oil revenue $ 72,008 $ 72,885 $ 73,349 $ 104,132 $ 115,286 Natural gas revenue 9,355 9,398 11,265 14,081 12,154 Total revenue 81,363 82,283 84,614 118,213 127,440 Impact of cash-settled derivatives (2,491) (267) (1,214) (4,501) (8,459) Adjusted Total Revenue $ 78,872 $ 82,016 $ 83,400 $ 113,712 $ 118,981 Total Production (Mboe) 1,838 2,021 2,074 2,439 2,391 Adjusted Total Revenue per Boe $ 42.91 $ 40.58 $ 40.21 $ 46.62 $ 49.76 Discretionary Cash Flow Reconciliation Net cash provided by operating activities $ 52,684 $ 43,128 $ 53,893 $ 80,186 $ 92,215 Changes in working capital (5,890) 8,968 7,777 8,642 (4,512) Payments to settle asset retirement obligations 765 816 250 216 366 Payments to settle vested liability share-based awards 8,662 4,511 3,089 Discretionary cash flow $ 56,221 $ 57,423 $ 61,920 $ 89,044 $ 91,158 Discretionary cash flow per diluted share $ 0.28 $ 0.28 $ 0.31 $ 0.44 $ 0.45 1. See Important Disclosure slides for disclosures related to Supplemental Non-GAAP Financial Measures 27