CALLON PETROLEUM COMPANY

CALLON PETROLEUM COMPANY Acquisition Overview April 2016

2 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. 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, 2015 filed with the Securities and Exchange Commission (the SEC ). 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. The Company uses the terms estimated ultimate recovery (or EUR ) that the SEC s rules may prohibit the Company from including in filings with the SEC. 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 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. Type/decline curves, estimated EURs, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from existing drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. As a result, such estimates may change significantly as results from more wells are evaluated. Estimates of EURs do not constitute reserves, but constitute estimates of contingent resources that the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, Internal Rate of Return (or IRR ) and Net Present Value (or NPV ) estimates are before taxes and assume Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic, G&A or other corporate level costs. This presentation includes certain estimates based on production, reserve and other data regarding the Big Star and AMI properties. The production, reserve and other data included have not been reviewed by our reserve engineer, DeGolyer and MacNaughton, and may vary from what is presented here. We cannot assure you that these estimates are accurate.

ADDITIONAL DISCLOSURES METRIC CALCULATION METHODOLOGIES $/Adjusted Acre: 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. $/ Delineated Horizontal Location: 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. 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. Recovery Factor: This calculation derives the implied percentage of the estimated original oil-in-place ( OIP ) that management expects can be recovered from a targeted zone in a capital efficient manner over the course of the productive life of the applicable number of wells needed for full section horizontal development. The recovery factor is arrived at by first calculating an estimate of the original OIP on a per section ( OIP/section ) basis (640 acres) for each zone that is prospective for horizontal development through various technical assessments of the subject area. The OIP/section figure is then normalized to a 960-acre drill spacing unit ( DSU ) for comparison purposes to the company s published single well type curves, which are displayed on a 7,500 (section-and-a-half) basis ( OIP/DSU ). The OIP/DSU is then compared to the result of multiplying management projections for per-well EURs by its assumptions for the proper well density (i.e., number of wells per DSU or section) to fully develop the acreage in order to arrive at a comparable estimated recovery factor. 3

OVERVIEW

COMBINED ACQUISITIONS Acquisitions include Big Star (primarily Howard County) and Western Reagan County AMI 12,951 core net surface acres delineated for Spraberry/Wolfcamp development (1) Approximately 192 net locations identified in zones delineated by Big Star and offset operators Assets currently produce 2,884 Boe/d, net (2) Big Star Net Acres: 14,089 acres Net Inventory (6) : 165 locations All-in Acquisition Metrics Total Consideration (3) $334 MM Total Net Surface Acreage Acquired 15,848 acres Central (legacy) Net Acres: 8,214 acres Net Inventory (6) : 327 locations Net Production (2) 2,884 Boe/d % Oil (2) 78% Net Delineated Horizontal Locations (6) $/Adjusted Acre (4) 192, net $15,630/acre $/ Delineated Hz Location (4) Callon Big Star Reagan AMI (5) Net Acres 17,233 14,089 1,759 Production (2) 12,400 Boe/d (79% oil) 1,931 Boe/d (82% oil) $1.29mm 953 Boe/d (68% oil) Delineated Inventory (6) 648 / 521 178 / 165 83 / 27 (Gross/Net) Acquired Acreage CPE Acreage Southern (legacy) Net Acres: 9,019 acres Net Inventory (6) : 194 locations Western Reagan County AMI (5) Net Acres: 1,759 acres Net Inventory (6) : 27 locations 1) Excludes 2,897 net acres in Dawson County. 2) Production figures are estimated 1Q16 average volumes. 3) Based on CPE closing price of $8.73 per share as of April 18, 2016. 4) Assumes $30,000 per flowing Boe to value PDP. Please refer to Metric Calculation Methodologies on Slide 3, for further clarity. 5) Reagan AMI metrics reflect the net impact of the acquisition of 55% of incremental western Reagan County assets and 27.5% selldown of legacy Garrison Draw working interests. 6) Delineated inventory includes: a) currently producing zones for Callon legacy acreage; b) Lower Spraberry, and B on Big Star acreage; c), Upper/Lower on AMI. 5

METRICS & COMPARABLES Big Star Metrics Moss Creek Acquisition of Tall City/Element 10/23/15 Purchase Price: ~$1,084mm Production, net: ~6,000 Boe/d Acreage, net: ~78,000 acres Diamondback Acquisition of Cobra Oil & Gas, etc. 5/6/15 Purchase Price: ~$438mm Production, net: ~2,500 Boe/d Acreage, net: ~11,948 acres Recent Howard Co. Transactions (1) Total Consideration (2) $301 MM Net Surface Acreage Acquired 14,089 acres 1Q16e Net Production (% oil) (3) 1,931 Boe/d (82% oil) Delineated Horizontal Locations 165, net $/Adjusted Acre (4) $17,270/acre $/ Delineated Hz Location (4) $1.47 mm Recent Howard Co. A&D Metrics (1) $40 Rock Oil Acquisition of Linn Energy Assets 7/2/15 Purchase Price: ~$281mm Production, net: ~2,000 Boe/d Acreage, net: ~6,400 acres Breitburn Acquisition of Antares Energy 10/24/14 Purchase Price: ~$123mm Production, net: ~600 Boe/d Acreage, net: ~3,700 acres Encana Acquisition of Athlon Energy 9/27/14 Purchase Price: ~$6,989mm Production, net: ~30,000 Boe/d Acreage, net: ~140,000 acres $M / Net Adjusted Acre (3) $30 $20 $10 $0 Encana Breitburn FANG Rock Oil Moss Creek CPE Athlon Antares Cobra Linn Tall City Big Star Time 1) Sources: 1Derrick, third-party press releases and investor presentations. Transactions include deals >$100mm occurring in Howard Co. since 2H14. Purchase price metrics reflect figures from transaction announcements, before giving effect to closing adjustments. 2) Based on CPE closing price of $8.73 per share as of April 18, 2016. 3) Production figures are estimated 1Q16 average volumes. 4) Production valued at the following per flowing Boe assumptions for transactions in a given year: $50,000 for 2014, $35,000 for 2015 and $30,000 for 2016. Please refer to Metric Calculation Methodologies on Slide 3, for further clarity. 6

DEEP HIGH-RETURN INVENTORY Acquired Properties Returns Are Competitive with Top-Tier Legacy Portfolio 83% Illustrative Type Curve EURs & Returns 52% 41% 36% 39% IRRs EURs 1050 MBoe 850 MBoe 700 MBoe 675 MBoe 725 MBoe Legacy Central Big Star AMI/Legacy South Lower Spraberry Lower Spraberry Lower Wellhead EUR 1,050 850 700 675 725 Oil Mix 83% 87% 88% 87% 76% D&C Cost ($M) $5,050 $5,050 $5,050 $5,050 $5,050 Lateral Length (Ft) 7,500 7,500 7,500 7,500 7,500 Single Well IRR (1) 83% 52% 41% 36% 39% ROI (1) 5.4x 4.5x 3.7x 3.6x 3.5x NPV ($MM) (1) $8.3 MM $6.1 MM $4.5 MM $4.1 MM $4.1 MM Gross / Net Locations 131 / 96 64 / 59 62 / 58 52 / 48 66 / 46 Spacing Assumption (2) 11 wells / section 8 wells / section 7 wells / section 6 wells / section 7 wells / section Full-Cycle Returns (3) Single Well IRR (1) n/a 31% 24% 21% 36% NPV ($MM) (1) n/a $4.6 MM $3.0 MM $2.6 MM $3.9 MM 1) Assumes NYMEX pricing as of April 8, 2016. NPV calculations assume a 10% discount rate. 2) Spacing Assumptions are based on geological and petrophysical surveys of the respective areas and through analogy to comparable producing zones/acreage. 3) Full-cycle IRRs and NPVs calculated by adding ~$1.47mm/ delineated Hz Location for Big Star acquisition (slide 7) and ~$0.16mm/ delineated Hz Location for Western Reagan Co. AMI acquisition. 7

CURRENT AFE ESTIMATES Drilling Completion Facilities $4,150 $5,050 $5,850 $6,650 Lateral Length 5,000 7,500 9,000 10,000 Stages 20 30 34 38 Drilling ($M) $1,550 $1,600 $1,700 $1,750 Completion ($M) $2,450 $3,300 $4,000 $4,750 Facilities ($M) (1) $150 $150 $150 $150 Total Estimated Cost Per Well ($M) $4,150 $5,050 $5,850 $6,650 1) Expense represents well-level facilities and excludes any central facilities. 8

ACQUISITION OVERVIEW: BIG STAR

BIG STAR ACREAGE SUMMARY Big Star Assets Provide a Substantial Footprint in Emerging Core Area (1) 17,298 gross / 14,089 net acres (> 80% operated; ~56% HBP) No drilling activity needed to hold acreage in 2016; 2017 obligations can be met with < 1 rig Multiple formations delineated by industry activity, including Lower Spraberry, and Acreage is well positioned for horizontal development, with average lateral length of over 8,300 Big Star Ponderosa Unit L 1H Lower Spraberry 30D IP: 915 Boe/d (88% Oil) Element Wright Unit 44-41 3H Lower Spraberry 30D IP: 1,084 Boe/d (91% Oil) Element Wright Unit 41-32 2H 30D IP: 948 Boe/d (90% Oil) Oxy Adams 4201WA 30D IP: 1,495 Boe/d (90% Oil) Energen Smith SN 48-37 #501H Lower Spraberry 30D IP: 895 Boe/d (79% Oil) Big Star Gunslinger Unit L 4H Lower Spraberry 30D IP: 696 Boe/d (89% Oil) Crownquest Gratis 32 R 1HB 30D IP: 1,063 Boe/d (88% Oil) Athlon Abel 18 3H 30D IP: 1,063 Boe/d (85% Oil) Crownquest S Wilkinson 181H 30D IP: 2,210 Boe/d (85% Oil) Element Wolfe-McCann Unit 10-15 2H 30D IP: 951 Boe/d (91% Oil) Tall City Hamlin 19-30 1H Lower Spraberry 30D IP: 1,074 Boe/d (89% Oil) Tall City Hamlin 20-29 1H 30D IP: 929 Boe/d (96% Oil) Athlon Williams 17 3H 30D IP: 1,234 Boe/d (82% Oil) Big Star Open Unit A 2H 30D IP: 1,326 Boe/d (90% Oil) Big Star Ryder Unit 2H 30D IP: 1,484 Boe/d (92% Oil) Big Star Masters Unit A 1H 30D IP: 1,406 Boe/d (91% Oil) Oxy May 1102 WA 30D IP: 1,262 Boe/d (86% Oil) Athlon Tubb 39 5H 30D IP: 1,594 Boe/d (73% Oil) 1) Sources: internal Big Star production data, offset operator and industry press releases and investor presentations of the respective or third-party operators from March 2014 through April 2016. 10

IRR at flat WTI Price Scenarios Cumulative Production (MBoe) INVENTORY OVERVIEW Gross Horizontal Location Inventory Big Star Type Curves 300 250 200 Long Laterals Short Laterals (2) (2) 52 124 120 100 80 Operated Hz Performance vs. Type Curve (7,500 ) Lower Spraberry TC TC TC Avg Big Star Well (3) 150 62 298 60 100 50 64 40 20 5 1 0 PDP DUC LSBY WC A WC B Prospective Total (1) Zones Lateral Length Breakdown >7,500 7,500 <7,500 Avg. Lower Spraberry 40 12 12 8,286 41 11 10 8,481 32 9 11 8,240 Prospective Zones (1) 79 23 22 8,341 0 0 30 60 90 120 150 180 Days on Production Type Curve IRRs at WTI Flat Pricing Scenarios (4) 80% Lower Spraberry 60% 40% 20% TOTAL 192 55 55 8,341 1) Prospective zones for Big Star acreage include Middle Spraberry and Wolfcamp D/Cline. 2) Long Laterals include gross laterals that are projected to be drilled to 7,500 or more. Short Laterals include those projected to be drilled to less than 7,500. 3) Avg Big Star Well reflects the actual average daily production volumes from five operated Big Star horizontals, normalized for lateral length (7,500 ) and downtime. 4) Assumes flat $2.50/MMBtu NYMEX natural gas prices. 0% $30/Bbl $40/Bbl $50/Bbl WTI Flat Assumption ($/bbl) 11

90D Cum (MBoe) DELINEATED STACKED PAY Over last 18 months, Howard Co. has been the site of many of the Midland Basin s high-profile transactions Lower Spraberry OIP (1) OIP (1) Well IP BO/Day Howard Co. has emerged as a new core area of the Midland Basin with well results that continue to attract operator capital and insulate activity levels despite current oil prices Originally underpinned by strong results in the WC A, industry activity in Howard Co. has expanded to delineate multiple zones with initial LSBY and WC B results tracking the success of their predecessor Industry delineation efforts continue to expand the sweet spots of these zones and may indicate incremental bench upside (i.e., select testing of the Middle Spraberry and Cline) 600 500 400 300 200 100 0 Howard County Hz Creaming Curve (2) Lower Spraberry Creaming curves use historic production to provide a potential indication of future well performance The slope of the line at any given point and the slope change with each successive well are illustrative 0 5 10 15 20 25 30 Well Count 1) Sources: NuTech, Texas Railroad Commission, internal Callon geological analysis. 2) Sources: DrillingInfo, IHS Enerdeq. 90-day cumulative production for single well pads based on volumes reported to Railroad Commission, normalized for reported perforated lateral length. Creaming curve is formed by ordering wells by first production date and adding the 90-day cumulative of each well to the sum total of the 90-day cumulatives of all the wells that preceded it. Well IP BO/Day 12

CORE LEVEL RESOURCE IN PLACE The depositional environment associated with the Big Star assets is analogous to our Central Basin area, resulting in similar rock types, log character and calculated OIP. One of the key differences is a coarser rock fabric in the Big Star area, which we believe will enhance productive capacity. Central MLB Midland Acreage (1) Big Star Star Acreage (1) GR Δ Log R 2 1 GR Δ Log R Upper Spraberry 3 Upper Spraberry Middle Spraberry Shale 35 50 MMBO / Section 1 2 3 Middle Spraberry Shale 25 40 MMBO / Section Lower Spraberry / Jo Mill Lower Spraberry Shale 35 55 MMBO / Section 1 2 3 Big Star CPE Central CPE South Callon Pro Forma Acreage Extent Lower Spraberry / Jo Mill Lower Spraberry Shale 25 45 MMBO / Section Dean Implied Recovery Factors (1) Dean WFMP-A 15 35 MMBO / Section CMB LS Big Star LS Big Star WC A WFMP-A 20 50 MMBO / Section OIP/section 45 MMBO 35 MMBO 35 MMBO WFMP-B 20 40 MMBO / Section OIP/DSU 68 MMBO 53 MMBO 53 MMBO Wells/DSU 11 8 7 WFMP-B 15 35 MMBO / Section WFMP-C EUR 883 MBO 739 MBO 622 MBO Total DSU EUR 9.7 MMBO 5.9 MMBO 4.4 MMBO WFMP-C Recovery Factor (2) 14.4% 11.3% 8.3% 1) Sources: NuTech, internal Callon geological and petrophysical analysis. All metrics presented are estimates based on geological and petrophysical analyses. Actual conditions may vary from the estimates presented here. 2) Please refer to Metric Calculation Methodologies on Slide 3, for further clarity. 13

ACQUISITION OVERVIEW: WESTERN REAGAN AMI

POST-TRANSACTION AMI Well-Aligned Western Reagan County AMI Forming AMI with non-op financial partner, TRP, in western Reagan Co. Transaction includes acquiring 55% of new AMI acreage (5,736 gross/4,745 net) in exchange for ~$33mm in cash and 27.5% of legacy Garrison Draw leasehold (3,204 gross/3,094 net) Establishes a cooperative effort to increase leasehold in an area that CPE views highly and continues to improve as it benefits from the application of next generation frac designs Lowers near-term funding needs for acquiring acreage within AMI and development Pro Forma AMI Leasehold Map Gross Hz Location Inventory CPE AMI Interest: 8,940 gross acres/4,853 net acres (100% operated) 300 Acquired Locations Garrison Draw 132 Acquired Acreage (55% interest in incremental AMI assets) 250 200 CPE: 2,610 net acres, post-transaction 150 38 257 45 Garrison Draw (72.5% interest in legacy assets post-ami) CPE: 2,243 net acres, post-transaction Acquired Acreage Garrison Draw 100 50 0 40 28 2 PDP DUC WC A Upper WC B Lower WC B Prospective (1) Zones Total 1) Prospective zones for AMI acreage include Lower Spraberry, Jo Mill, Wolfcamp C, Wolfcamp D/Cline. 15

WESTERN REAGAN WELL ACTIVITY Expanding in Area with Strong Performance in Multiple enches (1) Turner AR Unit 30HS IP24: 1,283 Boe/d (87% Oil) Ham Unit M 2 06HS IP24: 1,097 Boe/d (85% Oil) Turner AR Unit 35HS IP24: 1,428 Boe/d (87% Oil) Ham Unit RE M 2 32HA IP24: 1,615 Boe/d (86% Oil) Turner AR Unit 36HA IP24: 1,058 Boe/d (84% Oil) Ham Unit RE M 2 28HK Lower IP24: 1,094 Boe/d (88% Oil)) Turner AR Unit 31HA IP24: 1,122 Boe/d (77% Oil) Ham Unit RE M 2 02HA IP24: 1,089 Boe/d (86% Oil)) Turner AR Unit C 13HK Lower IP24: 1,260 Boe/d (85% Oil) Turner AR Unit A 32HK Lower FLOWING BACK Turner AR Unit B 08HK Lower IP24: 1,290 Boe/d (85% Oil) Turner AR Unit A 27HK Lower FLOWING BACK Callon University 27-34 4LH Lower 30D IP: 807 Boe/d (84% Oil) Turner AR Unit A 25HS WAITING ON COMPLETION Callon University 2 15AH 30D IP: 653 Boe/d (87% Oil) Turner AR Unit A 26HA WAITING ON COMPLETION 1) Source: DrillingInfo, Callon internal data and Texas Railroad Commission filings. 16

CALLON: PRO FORMA

INVENTORY OVERVIEW Potential Gross Horizontal Locations Legacy Callon Pro Forma Acquisitions 1,600 1,400 Central Midland Southern Midland 1,600 1,400 Central Midland Southern Midland Big Star 629 1,200 414 1,200 1,000 1,000 211 66 800 600 400 202 148 131 35 1,067 800 600 400 259 234 1,507 200 100 200 100 0 0 MSBY LSBY WC A Upper Lower Prospective Total MSBY LSBY WC A Upper Lower Prospective Total WC B WC B (1) Zones WC B WC B (1) Zones Pro Forma Effective Acreage Breakdown (Grand Total: 152,430 net) Gross Net Middle Spraberry 17,369 14,382 Gross Net Operated Producing Zones Lower Spraberry 28,125 23,190 35,141 27,177 Upper 33,861 25,800 Prospective Zones Clearfork 6,238 4,450 Jo Mill 19,367 15,292 Wolfcamp C 15,062 10,328 Lower 15,852 10,778 Wolfcamp D/Cline 28,674 21,033 Total 130,349 101,327 Total 69,341 51,103 1) Prospective zones include: Jo Mill, Wolfcamp C, Wolfcamp D/Cline for legacy Callon properties, Middle Spraberry and Wolfcamp D/Cline for Big Star acreage and Wolfcamp C and Wolfcamp D/Cline for western Reagan AMI. 18

DEVELOPMENT OUTLOOK Illustrative Pro Forma Program Rig Count Bear Scenario Base Scenario Bull Scenario 4 Bull Scenario includes addition of 3 rd rig in 1H17 to be allocated as returns warrant between legacy assets and recent acquisitions 3 2 Near-Term Plan maintains current rig count to achieve goal of self-funding for consecutive quarters while maintaining production momentum Base Scenario includes initiation of Howard Co. program in 4Q16/1Q17 and ~50-50 activity split in 2017 1 Plan to complete 3 DUCs on acquired assets in 2016 Bear Scenario assumes maintaining an active program on CMB LS to maximize capital efficiency and deploying 2 nd rig as needed to fulfill drilling obligations on acquired leasehold 0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 19