ACQUISITION OVERVIEW DELAWARE BASIN BOLT-ON ACQUISITION

ACQUISITION OVERVIEW DELAWARE BASIN BOLT-ON ACQUISITION

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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 ) and the prospectus supplement related to this offering. RESERVE-RELATED DISCLOSURES The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves, and accordingly are subject to substantially greater risk of being realized by the Company. EUR estimates and potential horizontal well locations have not been risked by Callon Petroleum Company (the Company ). Actual locations drilled and quantities that may be ultimately recovered from the Company s interest may differ substantially from the Company s estimates. There is no commitment by the Company to drill all of the potential horizontal drilling locations. Factors affecting ultimate recovery include the scope of the Company s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, commodity price levels, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of type/decline curves and per-well EURs may change significantly as development of the Company s oil and gas assets provides additional data. This presentation includes certain estimates based on production, reserve and other data regarding the Pending Acquisition properties. The production, reserve and other data included have not been reviewed by our reserve engineer, DeGolyer and MacNaughton or any other independent reserve engineer, and may vary from what is presented here. We cannot assure you that these estimates are accurate. Investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2017 and other reports filed with the SEC, available on our website or by request by contacting Investor Relations: Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077. You may also email the Company at ir@callon.com. You can also obtain our Form 10-K and other reports filed with the SEC by contacting the SEC directly at 1-800-SEC-0330 or by downloading it from the SEC s web site http://www.sec.gov. 2

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

Acquisition Overview ASSET HIGHLIGHTS PRO FORMA DELAWARE BASIN POSITION ~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 Significant base of high oil-cut (73% oil (1) ), lower decline production Established infrastructure enhances Callon s existing Delaware Basin capacity Key Acquisition Metrics 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 Implied Adjusted Transaction Metrics (3) $ / Net Acre $10,355 $ / Wolfcamp Net Acre $15,680 $ / Net Delineated Hz Location (2) $1.4mm Callon May 2018 Acquisition Increased WI in CPE Units ~47,500 PRO FORMA NET DELAWARE BASIN ACRES 1. Based on average net daily production for the quarter ended March 31, 2018 2. Includes 3BS, WCA and 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 4

Strategic Acquisition Complements Our Strategy True Bolt-On Directly adjacent and highly complementary to our existing Delaware Basin position Provides increased scale and focused core inventory expansion Benefits from existing geologic and technical data sets Top Tier Asset Quality High oil content production with established foundation of infrastructure Multiple delineated zones with the opportunity to enhance by implementing next generation completion designs Emerging zones being tested by offset operators and Callon offer additional upside Operational Leverage and Flexibility Compelling Value Proposition Advances Financial Objectives Contiguous footprint augments long lateral development and multi-well pad opportunities Leverage existing and under-construction infrastructure to lower costs and increase efficiency Limited near-term drilling obligations enhances development flexibility Attractive acquisition price relative to recent offset transactions in the area Accretive nature of acquisition drives improved cash flow per debt adjusted share and higher NAV per share Improves corporate returns on capital employed metrics Material current production creating near-term cash flow to support development Pro forma net debt / 1Q 18 annualized adjusted EBITDA of 2.1x, below upper leverage threshold of 2.5x (1) Accelerates path to free cash flow generation 1. Acquisition portion of pro forma 1Q 2018 EBITDA is calculated as follows: midpoint of revenue range less midpoint of direct operating expenses range of seller for 1Q 2018. 5

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) High 200 Wolfcamp Total OOIP (Mmbo/sec) 0 Low WOLFCAMP RESERVOIR PRESSURE 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) High 100% Wolfcamp Percent Oil 0% Low 3D SEISMIC COVERAGE Core operating area features structurally quiet basin floor with minimal faulting through position 3D Seismic Coverage 6

Building Scale in the Core of the Delaware December 2016 December 2017 May 2018 Callon Dec 2016 Callon May 2018 Callon Dec 2016 2017 Bolt-Ons Acquisition 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 7

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 8

Contiguous Acreage Benefits KEY BENEFITS OF INTEGRATED POSITION Increases working interests in numerous existing blocks Allows for extended laterals in contiguous sections Significantly increases number of long laterals Enhances optionality for multi-well pad development Leverages existing and planned infrastructure to reduce operating costs and enhance operating efficiency Trade potential to further consolidate position ACQUIRED OPERATED ACREAGE DISTRIBUTION ON CALLON OPERATED NET LATERAL FEET ON CALLON WITHIN 1-MILE OTHER OTHER WC 32% 43% 25% BS 25% 35% 40% WITHIN 1-MILE 9

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 provides ample capacity to facilitate cost-efficient, multi-well pad development 10

Upside Potential 2 nd Bone Spring & 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 L 1 K I A J E 3 C F B D 4 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) Source: Public reporting 11

% 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 Acquisition financing, including an opportunistic debt raise, preserves liquidity and maintains strong balance sheet and leverage metrics Pro forma net debt / 1Q 18 annualized adjusted EBITDA of 2.1x (1) Expected liquidity benefits from planned borrowing base redetermination ACQUISITION DRIVES SIGNIFICANT VALUE ENHANCEMENT 80% +67% 60% +51% 40% 20% +11% +26% 0% Shares Outstanding 1Q'18 Net Production (2) Net Acres Gross Hz Locations Current 202.0 MM 26.6 Mboe/d ~56,900 net acres 1,545 gross Hz locations Pro Forma 224.0 MM 33.4 Mboe/d ~86,100 net acres 2,581 gross Hz locations 1. Acquisition portion of pro forma 1Q 2018 EBITDA is calculated as follows: midpoint of revenue range less midpoint of direct operating expenses range of seller for 1Q 2018. 2. Based on average net daily production for the quarter ended March 31, 2018. 12

Mbbl per day Risk Management STRATEGY Portfolio approach with focus on total realized price Allow for upside pricing participation in a volatile differential market CRUDE OIL NYMEX WTI HEDGE PORTFOLIO (1) 25 20 Locking in downside protection to support cash flow for drilling program 2H18 average floor of above $50 2019 average floor of above $55 Methodically layering in Mid-Cush protection to mitigate financial risk 2018 Mid-Cush avg. hedge price of ($0.86) 2019 Mid-Cush avg. hedge price of ($2.30) 2020 Mid-Cush avg. hedge price of ($1.20) Continue to evaluate a variety of physical and financial risk mitigation alternatives to match longterm growth trajectory Established long-term gathering and sales contracts for incremental production Acquired properties covered under long-term agreements Increased production base provides benefits for marketing initiatives Additional multi-year term, firm sales agreements recently added to Callon portfolio 15 10 5 0 2H18 2019 15% 34% 49% 5% 66% 31% 2H18 2019 Swaps 2-Way Collars 3-Way Collars Deferred Premium Puts 1. Hedge portfolio as of May 22, 2018. 13

Callon Pure Play Peers <$10 Bn Market Cap Cochran Hockley Lubbock Cochran Hockley Lubbock Cochran Hockley Lubbock Cochran Hockley Lubbock Yoakum Terry Lynn Yoakum Terry Lynn Yoakum Terry Lynn Yoakum Terry Lynn Lea Gaines Dawson Borden Lea Gaines Dawson Borden Lea Gaines Dawson Borden Lea Gaines Dawson Borden NM TX Andrews Martin Howard NM TX Andrews Martin Howard NM TX Andrews Martin Howard NM TX Andrews Martin Howard Ector Midland Glasscock Ector Midland Glasscock Ector Midland Glasscock Ector Midland Glasscock Crane Upton Reagan Crane Upton Reagan Crane Upton Reagan Crane Upton Reagan Crockett Crockett Crockett Crockett Brewster Brewster Brewster Brewster Jagged Peak Terrell Val Verde Centennial Terrell Val Verde Callon May 2018 Acquisition Terrell Val Verde RSP Permian Terrell Val Verde Jagged Peak 1Q 18: Net acres: ~77,700 Net Mbo/d: 21.9 Op. margin ($/boe): $44.90 Centennial 1Q 18: Net acres: ~80,100 Net Mbo/d: 31.6 Op. margin ($/boe): $35.28 Callon 1Q 18 Pro Forma Net acres: ~86,100 Net Mbo/d: 25.6 Op. margin ($/boe): $43.92 RSP Permian 1Q 18 Net acres: ~91,900 Net Mbo/d: 45.3 Op. margin ($/boe): $40.34 Callon has amassed a highly economic acreage position ripe for full-scale development Source: Latest public investor presentations and 10Q filings 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 14

Key Takeaways Significant, complementary expansion of core Delaware position Directly offset acreage position drives material benefits for combined development plan Ability to leverage existing complementary infrastructure Current cash flow profile and robust full cycle economics create path for increased returns on capital Immediately accretive to key debt-adjusted per share metrics 15

APPENDIX

Crude Oil Hedge Contracts (1) Crude Oil (MBbl, Wtd Avg. $/Bbl) 2H18 1H19 2H19 1H20 2H20 Swaps Strike Price Costless Collars Short Call Price Put Price 1,104 $52.07 184 $60.50 $50.00 - - - - - - - - Three-way Collars Short Call Price Put Price Short Put Price 1,748 $60.86 $48.95 $39.21 1,629 $63.71 $53.89 $43.89 1,840 $63.70 $53.89 $43.89 - - Deferred Premium Puts Put Price Avg. Premium 522 $65.00 $2.26 905 $65.00 $6.45 920 $65.00 $6.45 - - Midland-Cushing Basis Differential Swap Price 2,484 ($0.93) - 552 ($2.30) 1,456 ($1.48) 1,472 ($0.93) Total NYMEX WTI Hedge Volume Weighted Average Floor Price 3,588 $52.43 2,534 $57.86 2,760 $57.67 - - 1. Hedge contracts as of May 22, 2018. 17

Natural Gas Hedge Contracts (1) Natural Gas (BBtu, Wtd. Avg. $/MMBtu) 1H18 2H18 Swaps Strike Price Costless Collars Short Call Price Put Price 1,706 $2.91 720 $3.84 $3.40 2,760 $2.91 - Total NYMEX Henry Hub Hedge Volume Weighted Average Floor Price 2,426 $3.06 2,760 $2.91 1. Hedge contracts as of May 22, 2018. 18