CALLON PETROLEUM COMPANY 4Q 2015 Earnings Presentation March 2, - PowerPoint PPT Presentation

CALLON PETROLEUM COMPANY 4Q 2015 Earnings Presentation March 2, 2016

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. Investors are urged to consider closely the disclosure in our Form 10-K 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

2015 ACCOMPLISHMENTS  Record daily Permian volumes of 9,610 Boe/d (80% oil); up 70% vs. FY14 Production  Grew 1P reserves 65% Y/Y to 54.3 MMBoe at “drill - bit” F&D of $8.98/boe and  Increased CMB LS type curve by >30% to >1 MMBoe Resource  Increased SMB WC “B” type curve by 46% to 871 Mboe  Two-stream per unit operating costs of $7.71/Boe in FY15; down ~30% vs. Operating $10.85/Boe in FY14 Cost  5 of 6 major producing fields on pipe (~79% of FY15 production) as of YE15; Structure lowered average transportation cost by >$1/bbl Operational  Achieved 100% HBP across all acreage Flexibility  Pivoted to high-grade near-term activity on top-returning asset (CMB LS)  Completed 33 gross horizontal wells in 2015 (1 st MS; 11 in LS; 21 in WC) Activity  Producing from five horizontal zones  Raised over $175mm (net) in equity to finance acquisitions and bolster Balance balance sheet, exiting 2015 at 2.8x Debt/Adjusted EBITDA and over Sheet $260 mm of liquidity 3

4Q15/RECENT HIGHLIGHTS  Record daily volumes of 10,598 Boe/d (80% oil); up 9% sequentially Production  YTD production trending above 11,700 Boe/d in 2016  2 of last 3 major fields placed on pipe, further improving transportation diffs Pricing  Combined with tightened regional basis, yields realized oil at 93% of NYMEX OPEX  Two-stream per unit operating costs of $6.47/Boe; down 19% sequentially  Average CWC per lateral foot of ~$680 (current AFE); down 20% from 3Q15 Well Cost  Leading- edge 7,500’ AFE’s of $5.1mm are down 35% vs. peak (3Q14)  Placed-on-Production 9 gross (6.2 net) horizontal wells in 4Q15 (including Activity 4.3 net in LS, 1 st MS well and a SMB well fully HBP’ing acreage)  Average 30- day IP/1,000’ lateral in 4Q15 of 126 Boe/d  Increased Adjusted EBITDA margin to ~73% despite a 40% decrease in average realized pricing since 4Q14  Bolstered hedge portfolio to 64% of FY16e oil ($50.25/bbl, long put/swap) Financial and 36% of FY16e gas ($2.52/mmbtu, swap) at midpoint of guidance  Exchanged 719,000 shares of common stock for $6mm of preferred stock; lowering annual dividend expense at attractive relative valuation  Acquired working interests (933 net acres) in multiple core operating areas Acquisitions within our existing fields at attractive valuation  Actively evaluating several packages 4

YE15 RESERVES: BREAKDOWN Breakdown: YE15 vs. YE14 2015 Proved Reserve Progression YE14: 32.8 MMBoe YE15: 54.3 MMBoe 60 PDP ↑ 57% Total ↑ 65% 22% 22% 20% 20% 50 78% 78% 80% 80% rves (MMBoe) 40 Oil Gas 30 Drill-Bit F&D: $8.9 .98/Boe 1P Reserves 55% 55% (INCLUDING ALL 45% 45% REVISIONS) 47% 47% 51% 51% 20 10 PDP PDNP PUD Total Reserve Replacement: 711% (INCLUDING ALL Breakdown: PUDs by Zone REVISIONS) 0 SMB LWC B 60 YE14 Extensions Production Revisions Purchase YE15 50 SMB UWC B 40 Conservative PUD philosophy, no vertical bookings, • SMB WC A operating and capital cost control insulated reserve base 30 CMB WC B from large downward revisions 20 10 CMB LS Well outperformance and conversion of probables (i.e., • 0 Lower Spraberry) to PDP drove strong 2015 reserve growth CMB MS Well Count 5

YE15 RESERVES: METRICS Peer-Leading YE15 Unadjusted Reserve Performance (a) Lowest F&D Cost Smallest YE15 Price-Driven Revisions al 1P $20 20% es F&D ($/Boe) /Total 15% ns/Tot $15 e Revisions 10% 5% $10 ources Price FY15 All-Sou 0% CPE Peer 1 Peer 2 Peer 3 $5 Best YoY PV-10 Performance $0 CPE Peer 1 Peer 2 Peer 3 Change in PV-10 (Y/Y) PV-10 as % of RCF Commitment / YE14) CPE Peer 1 Peer 2 Peer 3 Highest Reserve Replacement YE15 PV-10 RCF Covera 0% 2.5x e in PV-10 (YE15/ nt ement -10% 2.0x 600% anic Reserve Replacem -20% 1.5x 400% -30% 1.0x Change erage -40% 0.5x 200% ge -50% 0.0x Organ 0% Strong underlying proved asset value CPE Peer 1 Peer 2 Peer 3 6 a) Peers include FANG, PE, and RSPP; PV-10 is based on YE15 standardized measure; F&D, reserve replacement, price revisions and standardized measure according to peer YE15 10-K filings.

OPERATIONS UPDATE • 88 Gross Hz Producing Wells (a) CaBo Middle Spraberry • 6 Gross Wells in Process (a) Lower Spraberry • 9 Gross Wells Placed on Production (“POP”) in 4Q15 (b) Wolfcamp B 4Q15 POPs: Pecan Acres 3 LS 1 MS  Strong first Middle Spraberry well with IP-24 of 1,078 Boe 4Q15 POPs:  Increased LS type curve to over 1MM BOE with 1 LS  Placed-on-Production two continued outperformance 1 WC B 10,000’ wells joint with RSPP  Strong 180-Day performance; Carpe Diem 22A1 #3H with >106K Boe cumulative production (4,709’)  2016 WC A test planned in 4Q15 POPs: RSPP partnership 2 LS • Successful pivot to Central Area for 2016 Lower Spraberry focus • Transitioned to a one-rig program in 1Q16 to protect balance sheet and enhance  First test of Lwr LS chevron optionality for acquisitions/acceleration pattern, establishing 2 nd • First Middle Spraberry online in Oct 2015 productive bench in that zone  Expected on pipe ~MY16 • Five established Hz zones in portfolio a) As of February 22, 2016. b) Includes one Lower WCB well placed on production in our Southern Area Garrison Draw field. 7